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

FORM 10-K

 

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

For the fiscal year ended June 30, 2007

OR

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

Commission File Number 000-52281

Energy XXI (Bermuda) Limited

Bermuda	98-0499286

Canon’s Court, 22 Victoria Street,
PO Box HM 1179,
Hamilton HM EX, Bermuda

Telephone: 441-295-2244

Securities registered pursuant to Section 12(b) of the Act:
Common Stock, par value $.001 per share

The above securities are registered on the NASDAQ Capital Market

Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $.001 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o NO x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o NO x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

Large accelerated filer o	Accelerated filer o	Non-accelerated filer x

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $319,946,895 based on the closing sale price of $5.50 per share as reported on NASDAQ on September 21, 2007.

The number of shares of the registrant’s common stock outstanding on September 21, 2007, was 84,219,406.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrants definitive proxy statement for its 2007 Annual Meeting of Shareholders have been incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

			Page
		PART I
Item 1		Business		3
Item 1A		Risk Factors		6
Item 1B		Unresolved Staff Comments		15
Item 2		Properties		16
Item 3		Legal Proceedings		20
Item 4		Submission of Matters to a Vote of Security Holders		20
		Executive Officers of the Registrant		20
		PART II
Item 5		Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		23
Item 6		Selected Financial Data		25
Item 7		Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 7A		Quantitative and Qualitative Disclosures About Market Risk		35
Item 8		Financial Statements and Supplementary Financial Information		36
Item 9		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		65
Item 9A		Controls and Procedures		65
Item 9B		Other Information		65
		PART III
Item 10		Directors, Executive Officers and Corporate Governance		66
Item 11		Executive Compensation		66
Item 12		Security Ownership of Certain Beneficial Owners and Management Related Shareholder Matters		66
Item 13		Certain Relationships and Related Transactions and Director Independence		66
Item 14		Principal Accountant Fees and Services		66
		PART IV
Item 15		Exhibits and Financial Statement Schedules		67
Glossary of Oil and Natural Gas Terms				70
Signatures				72

Forward-Looking Statements

Discussions of our future plans, expectations, objectives and anticipated performance in periodic reports filed by us with the SEC (or documents incorporated by reference therein) may include projections or other forward-looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by the words “expects,” “anticipates,” “intends,” “plans,” “believes,” “should” and similar expressions. Projections and forward-looking statements are based on assumptions which we believe are reasonable, but are by their nature inherently uncertain. In all cases, there can be no assurance that such assumptions will prove correct or that projected events will occur, and actual results could differ materially from those projected. See Item 1A “Risk Factors” and Item 7A “Quantitative and Qualitative Disclosures about Market Risk” for some of the important factors that could cause actual results to differ from any such projections.

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PART I

Item 1. Business

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

We operate geographically focused producing reserves and target the acquisition of oil and gas properties with which we can add value by increasing production and ultimate recovery of reserves, whether through exploitation or exploration, often using reprocessed seismic data to identify previously overlooked opportunities. For the year ended June 30, 2007, approximately 84 percent of our drilling capital was spent on exploitation, with the balance split between lower-risk and higher-impact exploration plays. From the April 2006 acquisition of our largest field, South Timbalier 21, through June 30, 2007, our focused exploitation program delivered an 89 percent increase in daily field production. Our exploitation of this field during the year ended June 30, 2007 involved the drilling of 12 gross wells. We have several remaining drilling and re-completion opportunities in South Timbalier 21 and anticipate a reduced activity level at this field as we increase efforts elsewhere.

At June 30, 2007, our total proved reserves were 55.6 MMBoe. We operated or had an interest in 338 producing wells on 131,235 net developed acres, including interests in 60 producing fields. All of our properties are located on the Gulf Coast and in the Gulf of Mexico, with approximately 76 percent of our proved reserves being offshore. This concentration facilitates our ability to manage the operated fields efficiently, and our high number of wellbore locations provides diversification of our production and reserves. We believe managing our assets is a key strength, and approximately 75 percent of our proved reserves are on properties operated by us. We have a seismic database covering approximately 2,300 square miles, primarily focused on our existing operations. This database has helped us identify at least 35 development and exploration opportunities. We believe the mature legacy fields on our recently acquired properties will lend themselves well to our aggressive exploitation strategy and expect to identify incremental exploration opportunities on the properties.

We actively manage price risk and hedge a high percentage of our proved developed producing reserves to enhance revenue certainty and predictability. Our disciplined risk management strategy provides substantial price protection so that our cash flow is largely driven by production results rather than commodity prices. This greater price certainty allows us to efficiently allocate our capital resources and minimize our operating cost. For further information regarding our risk management activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk”.

Our exploration and production activities commenced in April 2006 upon our acquisition of Marlin Energy Offshore, LLC and its affiliates (“Marlin”), whose Gulf of Mexico assets consisted of working interests in 34 oil and gas fields with 108 producing wells. The net proved reserve base of the Marlin properties totaled 25.2 MMBoe as of June 30, 2007. In July 2006, we acquired additional oil and gas working interests in 21 onshore and inland water Louisiana Gulf Coast fields from affiliates of Castex Energy, Inc. (“Castex”). The Castex properties held net proved reserves of 10.2 MMBoe as of June 30, 2007. On June 8, 2007, we acquired certain oil and natural gas properties in the Gulf of Mexico (the “Pogo Properties”) from Pogo Producing Company (the “Pogo Acquisition.”) The Pogo Acquisition included working interests in 28 oil and gas fields. The net proved reserve base of the Pogo Properties totaled 20.2 MMBoe as of June 30, 2007. In the month ended June 30, 2007, the Pogo Properties added 7.9 MBoed to our production level.

Marketing and Customers

We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority

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of our operated gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

Shell Trading Company accounted for approximately 35 percent of our total oil and natural gas revenues in fiscal year 2007. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all of our production in the absence of the customer listed above. Therefore, we believe that the loss of the customer listed above would not be expected to have a significant impact on our ability to market our oil and natural gas production or our results of operations.

We transport most of our oil and gas through third-party gathering systems and pipelines. Transportation space on these gathering systems and pipelines is normally readily available. While our ability to market our oil and gas has only been infrequently limited or delayed, if transportation space is restricted or is unavailable, cash flow from the affected properties could be adversely impacted.

Competition

We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies, individuals, drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and gas business for a much longer time than our company. These companies may be able to pay more for productive oil and gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Regulatory Matters

Regulation of Oil and Gas Production, Sales and Transportation

The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions in which we operate also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the unitization or pooling of oil and gas properties and the establishment of maximum rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports. The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas.

We operate various gathering systems. The United States Department of Transportation and certain governmental agencies regulate the safety and operating aspects of the transportation and storage activities of these facilities by prescribing standards. However, based on current standards concerning transportation and storage activities and any proposed or contemplated standards, we believe that the impact of such standards is not material to our operations, capital expenditures or financial position.

All of our sales of our natural gas are currently deregulated, although governmental agencies may elect in the future to regulate certain sales.

Environmental Regulation

Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the discharge and disposition of generated waste materials and waste management, the reclamation and abandonment of wells, sites and facilities, financial assurance under the Oil Pollution Act of 1990 and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

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The environmental laws and regulations applicable to us and our operations include, among others, the following United States federal laws and regulations:

• Clean Air Act, and its amendments, which governs air emissions;

• Clean Water Act, which governs discharges to waters of the United States;

• Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);

• Resource Conservation and Recovery Act, which governs the management of solid waste;

• Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States;

• Emergency Planning and Community Right-to-Know Act, which requires reporting of toxic chemical inventories;

• Safe Drinking Water Act, which governs the underground injection and disposal of wastewater; and

• U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.

We routinely obtain permits for our facilities and operations in accordance with these applicable laws and regulations on an ongoing basis. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations.

The ultimate financial impact of these environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on our operations. In addition, any non-compliance with such laws could subject us to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location. Costs, for example, may be incurred for air emission permits, spill contingency requirements, and discharge or injection permits. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.

We are committed to the protection of the environment throughout our operations and believe that it is in substantial compliance with applicable environmental laws and regulations. We believe that environmental stewardship is an important part of our daily business and will continue to make expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. The insurance coverage maintained by us provides for the reimbursement to us of costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure pollution and similar environmental risks. We do not anticipate that it will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

Employees

We had 80 and 30 employees at June 30, 2007 and June 30, 2006, respectively. At June 30, 2007, the Company had no union employees.

Web Site Access to Reports

Our Web site address is www.energyxxi.com. We make available, free of charge on or through our Web site, our annual report, Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the United States Securities and Exchange Commission.

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Item 1A. Risk Factors

Because we have a limited operating history, you may not be able to evaluate our current and future business prospects accurately.

We have a limited operating and financial history upon which you can base an evaluation of our current and future business. The results of exploration, development, production and operation of our properties may differ from that of prior owners.

The possible lack of business diversification may adversely affect our results of operations.

Unlike other entities that are geographically diversified, we will not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. By consummating only offshore Gulf of Mexico and Louisiana acquisitions our lack of diversification may:

• subject us to numerous economic, competitive and regulatory developments, any or all of which may have a substantial adverse impact upon the particular industry in which we operate; and

• result in our dependency upon a single or limited number of reserve basins.

Our indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities.

We have incurred substantial indebtedness in acquiring our properties. Our leverage and the current and future restrictions contained in the agreements governing our indebtedness may reduce our ability to incur additional indebtedness, engage in certain transactions or capitalize on acquisition or other business opportunities. Our indebtedness and other financial obligations and restrictions could have important consequences. For example, they could:

• impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general corporate purposes or other purposes;

• result in higher interest expense in the event of increases in interest rates since some of our debt is at variable rates of interest;

• have a material adverse effect if we fail to comply with financial and restrictive covenants in any of our debt agreements, including an event of default if such event is not cured or waived;

• require us to dedicate a substantial portion of future cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate requirements;

• limit our flexibility in planning for, or reacting to, changes in our business and industry; and

• place us at a competitive disadvantage to those who have proportionately less debt.

If we are unable to meet future debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity or sell assets. We may then be unable to obtain such financing or capital or sell assets on satisfactory terms, if at all.

We expect to have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.

We expect to make substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas reserves. Our capital requirements will depend on numerous factors, and we cannot predict accurately the timing and amount of our capital requirements. We intend to primarily finance our capital expenditures through cash flow from operations. However, if our capital requirements vary materially from those provided for in our current projections, we may require additional financing sooner than anticipated. A decrease in expected revenues or adverse change in market conditions could make obtaining this financing economically unattractive or impossible. Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely

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affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations. As a result, we may lack the capital necessary to complete potential acquisitions or to capitalize on other business opportunities.

Risks Associated with Acquisitions and Our Risk Management Program

Our acquisitions may be stretching our existing resources.

Since our inception in July 2005, we have made three major acquisitions and have become a reporting company in the United States. These transactions may prove to stretch our internal resources and infrastructure. As a result, we may need to invest in additional resources, which will increase our costs. Any further acquisitions we make over the short term would likely exacerbate these risks.

We may be unable to successfully integrate the operations of the properties we acquire.

Integration of the operations of the properties we acquire with our existing business will be a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:

• operating a larger organization;

• coordinating geographically disparate organizations, systems and facilities;

• integrating corporate, technological and administrative functions;

• diverting management’s attention from other business concerns;

• an increase in our indebtedness; and

• potential environmental or regulatory liabilities and title problems.

The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

In addition, we face the risk of identifying, competing for and pursuing other acquisitions, which takes time and expense and diverts management’s attention from other activities.

We may not realize all of the anticipated benefits from our acquisitions.

We may not realize all of the anticipated benefits from our prior acquisitions and from future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than unexpected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices.

If we are unable to effectively manage the commodity price risk of our production if energy prices fall, we may not realize the anticipated cash flows from our acquisitions.

Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Therefore, there is the possibility that we may be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we do not manage or are not capable of managing the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves.

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If we place hedges on future production and encounter difficulties meeting that production, we may not realize the originally anticipated cash flows.

Our assets consist of a mix of reserves, with some being developed while others are undeveloped. To the extent that we sell the production of these reserves on a forward-looking basis but do not realize that anticipated level of production, our cash flow may be adversely affected if energy prices rise above the prices for the forward-looking sales. In this case, we would be required to make payments to the purchaser of the forward-looking sale equal to the difference between the current commodity price and that in the sales contract multiplied by the physical volume of the shortfall. There is the risk that production estimates could be inaccurate or that storms or other unanticipated problems could cause the production to be less than the amount anticipated causing us to make payments to the purchasers pursuant to the terms of the hedging contracts.

Risks Related to the Oil and Gas Business

Oil and natural gas prices are volatile, and a decline in oil and natural gas prices would affect our financial results and impede growth.

Our future revenues, profitability and cash flow will depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

• domestic and foreign supplies of oil and natural gas;

• price and quantity of foreign imports of oil and natural gas;

• actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

• level of consumer product demand;

• level of global oil and natural gas exploration and productivity;

• domestic and foreign governmental regulations;

• level of global oil and natural gas inventories;

• political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;

• weather conditions;

• technological advances affecting oil and natural gas consumption;

• overall U.S. and global economic conditions; and

• price and availability of alternative fuels.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us having to make substantial downward adjustments to our estimated proven reserves and could have a material adverse effect on our financial condition and results of operations.

To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition and results of operations.

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Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or underlying assumptions of the Marlin, Castex or Pogo properties will materially affect the quantities and present value of those reserves.

Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized herein. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Unless we replace crude oil and natural gas reserves our future reserves and production will decline.

Our future crude oil and natural gas production will depend on our success in finding or acquiring additional reserves. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire additional reserves.

Relatively short production periods or reserve life for Gulf of Mexico properties subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years when compared to other regions in the United States. Typically, 50 percent of the reserves of properties in the Gulf of Mexico are depleted within three to four years. Due to high initial production rates, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from other producing reservoirs. The vast majority of our existing operations are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.

Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than we. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from the MMS are acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and

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purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute exploration and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services has increased during the past year as oil and gas companies have sought to increase production. While we currently have excellent relationships with oil field service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

The geographic concentration of our properties in the Gulf of Mexico subjects us to an increased risk of loss of revenue or curtailment of production from factors affecting the Gulf of Mexico specifically.

The geographic concentration of our properties in the Gulf of Mexico means that some or all of the properties could be affected should the Gulf of Mexico experience:

• severe weather;

• delays or decreases in production, the availability of equipment, facilities or services;

• delays or decreases in the availability of capacity to transport, gather or process production; and/or

• changes in the regulatory environment.

For example, the oil and gas properties that we acquired in April 2006 were damaged by both Hurricanes Katrina and Rita, which required us to spend a considerable amount of time and capital on inspections, repairs, debris removal, and the drilling of replacement wells. Although we maintain insurance coverage to cover a portion of these types of risks, there may be potential risks associated with our operations not covered by insurance. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss.

Because all or a number of the properties could experience any of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

Our future business will involve many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

We engage in exploration and development drilling activities. Any such activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of a gas or oil well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.

Our business involves a variety of inherent operating risks, including:

• fires;

• explosions;

• blow-outs and surface cratering;

• uncontrollable flows of gas, oil and formation water;

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• natural disasters, such as hurricanes and other adverse weather conditions;

• pipe, cement, subsea well or pipeline failures;

• casing collapses;

• mechanical difficulties, such as lost or stuck oil field drilling and service tools;

• abnormally pressured formations; and

• environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:

• injury or loss of life;

• severe damage to and destruction of property, natural resources and equipment;

• pollution and other environmental damage;

• clean-up responsibilities;

• regulatory investigations and penalties;

• suspension of our operations; and

• repairs to resume operations.

Our offshore operations will involve special risks that could affect operations adversely.

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to the fact that this is not economically viable. We therefore may not be able to rely on insurance cover in the event of such natural phenomena. Currently, we have only one deepwater leasehold block with no production or proved reserves. However, we may evaluate activity in the deepwater Gulf of Mexico in the future. Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Deepwater wells use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.

The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.

The properties we acquire may not produce as expected, may be in an unexpected condition and we may be subject to increased costs and liabilities, including environmental liabilities. Although we will review properties prior to acquisition in a manner consistent with industry practices, such reviews are not capable of identifying all potential conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. We focus our review efforts on the higher-value properties or properties with

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known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to fully assess their condition, any deficiencies, and development potential. Inspections may not be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Market conditions or transportation impediments may hinder access to oil and gas markets or delay production.

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. In deepwater operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms owned or operated by others and the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.

We will not be the operator on all of our properties and therefore will not be in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on such properties.

As we carry out our planned drilling program, we will not serve as operator of all planned wells. We currently operate approximately 75 percent of our properties. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

• the timing and amount of capital expenditures;

• the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

• the operator’s expertise and financial resources;

• approval of other participants in drilling wells;

• selection of technology; and

• the rate of production of the reserves.

Our insurance may not protect us against business and operating risks.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. As a result, we procure other desirable insurance on commercially reasonable terms, if possible. Although we will maintain insurance at levels we believe is appropriate and consistent with industry practice, we will not be fully insured against all risks,

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including business interruption insurance which cannot be sourced on economic terms, and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. As a result of a number of recent catastrophic events like the terrorist attacks on September 11, 2001 and Hurricanes Ivan, Katrina and Rita, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered extensive damage from Hurricanes Ivan, Katrina and Rita. As a result, insurance costs have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is as severe as it was in 2005, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. A number of industry participants have previously maintained business interruption insurance. This insurance may not be economically available in the future, which could adversely impact business prospects in the Gulf of Mexico and adversely impact our operations. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

Our operations will be subject to environmental and other government laws and regulations that are costly and could potentially subject us to substantial liabilities.

Crude oil and natural gas exploration and production operations in the United States and the Gulf of Mexico are subject to extensive federal, state and local laws and regulations. Companies operating in the Gulf of Mexico are subject to laws and regulations addressing, among others, land use and lease permit restrictions, bonding and other financial assurance related to drilling and production activities, spacing of wells, unitization and pooling of properties, environmental and safety matters, plugging and abandonment of wells and associated infrastructure after production has ceased, operational reporting and taxation. Failure to comply with such laws and regulations can subject us to governmental sanctions, such as fines and penalties, as well as potential liability for personal injuries and property and natural resources damages. We may be required to make significant expenditures to comply with the requirements of these laws and regulations, and future laws or regulations, or any adverse change in the interpretation of existing laws and regulations, could increase such compliance costs. Regulatory requirements and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations.

Our oil and gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

• require the acquisition of a permit before drilling commences;

• restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

• impose substantial liabilities for pollution resulting from operations.

Failure to comply with these laws and regulations may result in:

• the imposition of administrative, civil and/or criminal penalties;

• incurring investigatory or remedial obligations; and

• the imposition of injunctive relief.

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Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to be in compliance in all material respects with all applicable environmental laws and regulations, we cannot assure you that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability.

We are unable to predict the effect of additional environmental laws and regulations which may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

Under certain environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, or if current or prior operations were conducted consistent with accepted standards of practice. Such liabilities can be significant, and if imposed could have a material adverse effect on our financial condition or results of operations.

Other Risks

If we are not able to implement the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 in a timely manner or with adequate compliance, we may be unable to provide the required financial information in a timely and reliable manner and may be subject to sanctions by regulatory authorities.

Changing laws, regulations and standards relating to corporate governance and public disclosure, including the Sarbanes-Oxley Act of 2002 and related regulations implemented by the SEC, are creating uncertainty for public companies, increasing legal and financial compliance costs and making some activities more time consuming. We are evaluating our internal controls systems to allow management to report on, and our independent auditors to attest to, our internal controls. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act. While we anticipate being able to fully implement the requirements relating to internal controls and all other aspects of Section 404 by our June 30, 2008 deadline, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations since there is presently no precedent available by which to measure compliance adequacy. If we are not able to implement the requirements of Section 404 in a timely manner or with adequate compliance, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. Any such action could adversely affect our financial results or investors’ confidence in our company. In addition, the controls and procedures that we will implement may not comply with all of the relevant rules and regulations of the SEC. If we fail to develop and maintain effective controls and procedures, we may be unable to provide the financial information in a timely and reliable manner.

We depend on key personnel, the loss of any of whom could materially adversely affect future operations.

Our success will depend to a large extent upon the efforts and abilities of our executive officers. The loss of the services of one or more of these key employees could have a material adverse effect on us. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our exploitation strategy as quickly as we would otherwise wish to do.

Unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated, such costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations.

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If we are unable to acquire or renew permits and approvals required for operations, we may be forced to suspend or cease operations altogether.

The construction and operation of energy projects require numerous permits and approvals from governmental agencies. We may not be able to obtain all necessary permits and approvals, and as a result our operations may be adversely affected. In addition, obtaining all necessary permits and approvals may necessitate substantial expenditures and may create a risk of expensive delays or loss of value if a project is unable to function as planned due to changing requirements or local opposition.

We may be taxed as a United States Corporation.

We are incorporated under the laws of Bermuda because of our long-term desire to have substantial business interests outside the U.S. and recent legislation in the U.S. that penalizes domestic corporations that reincorporate in a foreign country.

We plan to purchase any U.S. assets through our wholly owned subsidiary Energy XXI USA, Inc. Energy XXI USA, Inc. and its subsidiaries will pay U.S. taxes on U.S. income. We do not currently intend to engage in any business activity in the U.S. However, there is a risk that some or all of our income could be challenged, and considered as effectively connected to a U.S. trade or business, and therefore subject to U.S. taxation. In consideration of this risk, we and our U.S. subsidiaries will implement certain operational steps to separate the U.S. operations from our other operations. In general, employees based in the U.S. will be employees of our U.S. subsidiaries, and will be paid for their services by such U.S. subsidiaries. Salaries of our employees who are resident in the U.S. and who render services to the U.S. business activities will be allocated as expenses of the U.S. subsidiaries.

Item 1B. Unresolved Staff Comments

None

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Item 2. Properties

Our properties are primarily located in the U.S. Gulf of Mexico waters and the Gulf Coast onshore. Below are descriptions of our significant properties.

South Timbalier 21 Field. We have a 100 percent working interest in the South Timbalier 21 field, located six miles offshore of Lafourche Parish, Louisiana in approximately 50 feet of water on Outer Continental Shelf (“OCS”) blocks South Timbalier 21, 22, 23, 27 and 28 as well as two state leases. The field is bounded on the north by a major Miocene expansion fault. Miocene sands are trapped structurally and stratigraphicaly from 7,000 feet to 15,000 feet in depth. Minor faulting that is secondary to the major normal fault separates hydrocarbon accumulations into individual compartments. The field was discovered by Gulf Oil in the late 1950s and has produced in excess of 350 MMBoe since production first began in 1957. There are 11 major production platforms and 75 smaller structures located throughout the field. Since July 1, 2006, we have drilled 12 gross wells. The field’s average daily gross production for the quarter ended June 30, 2007 was 10.7 MBoed. South Timbalier 21 accounted for approximately 54 percent of our net production for the second half of the year ended June 30, 2007. At June 30, 2007, net proved reserves for the field were 18.4 MMBoe, 68 percent of which was oil.

Main Pass 61 Field. We have a 50 percent working interest in and operate the Main Pass 61 field, located near the mouth of the Mississippi River in approximately 90 feet of water. The field produces from the Upper Miocene Disc. 12 sand, which is a black oil reservoir that is being waterflooded to maximize recovery. There are 15 producing wells and five major production platforms located throughout the field, which had net production for the month ended June 30, 2007 of 2.8 MBoed. At June 30, 2007, net proved reserves for the field were 8.1 MMBoe.

Rabbit Island Field. We have a 99.9 percent working interest in the Rabbit Island field, located in Louisiana state waters (state lease 340) in Iberia and St. Mary Parishes, 95 miles southwest of New Orleans. We operate the field, which covers approximately 27,000 acres. Discovered in 1939 by Texaco, this field has produced more than 1.2 Tcf (trillion cubic feet) of natural gas. The field is a structurally complex, faulted, shallow piercement salt dome with associated radial faulting. There are 30 producing horizons (Pleistocene to Miocene) ranging from 1,600-12,000 feet. We have drilled 9 gross wells since July 1, 2006. The field’s average daily net production for the quarter ended June 30, 2007 was 1.3 MBoed. At June 30, 2007, net proved reserves for the field were 6.3 MMBoe, 9 percent of which was oil.

Main Pass 72 Field. We have a 50 percent working interest in and operate the Main Pass 72 field, located in approximately 100 feet of water near the mouth of the Mississippi River and in close proximity to Main Pass 61 field. This field consists of OCS blocks Main Pass 72, 73, and 74. Production is from the Upper Miocene sands ranging in depths from 5,000 to 12,500 feet. Three producing platforms and one central facility are located throughout the field. At June 30, 2007, net proved reserves for the field were 3.5 MMBoe.

South Pass 49 Field. We have a 33 percent working interest in and operate the South Pass 49 field unit, located near the mouth of the Mississippi River in approximately 300 feet of water. The field unit consists of the D69 and D70 sands, ranging in depth from 8,700 to 9,400 feet, on OCS blocks South Pass 33, 48, and 49, where net production for the month ended June 30, 2007 was 0.3 MBoed. We also have a 10 percent working interest in the non unit, which consists of 12 additional producing sands ranging in depth from 7,200 to 9,000 feet. At June 30, 2007, our net proved reserves for the field were 1.4 MMBoe.

Lake Salvador Field and Joint Development Agreement. We have entered into a Joint Development Agreement (JDA) with Castex for the Lake Salvador Project, in which we have a 50 percent working interest. The project covers 1,680 square miles south of New Orleans in an area where fields have produced in excess of 700 MMBbls and 7.0 Tcf of natural gas. The project will have in excess of 1,000 square miles of 3-D seismic data, which will be reprocessed and merged to create one of the largest continuous 3-D surveys in south Louisiana. Currently, the JDA has lease options on 80,000 acres within the Lake Salvador Project, with the opportunity to pick up an additional 25,000 acres. We expect to initiate exploration drilling within the project area during fiscal 2008.

Exploration Agreement. In July 2006, we entered into an exclusive 50/50 Exploration Agreement with Castex for 24 months covering an Area of Mutual Interest (“AMI”) across more than 1,500,000 acres in

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south Louisiana. Both we and Castex may generate and operate prospects within the AMI, with operatorship determined by the party generating an individual prospect, proximity to a party’s existing facilities and rig availability.

Centurion Exploration Company Agreements

Gridiron Project

Energy XXI Gulf Coast, Inc. and Centurion Exploration Company entered into a Participation Agreement dated January 26, 2007 covering approximately 100,000 gross acres in southeastern Louisiana. Pursuant to this agreement, we paid a consideration of approximately $2.3 million to acquire working interests in seven prospects within the Gridiron Project AMI.

We have the option to drill and anticipate drilling six to eight exploratory wells within the Gridiron project over the next 12 months. We will bear 66.67 percent of the costs of the initial well on each prospect we elect to drill. Failure to participate in the drilling of any initial prospect well or failure to commence the drilling of any initial prospect well within certain time deadlines will result in forfeiture of the interest acquired and the initial consideration paid, on a prospect by prospect basis.

Productive Wells

Our working interests in productive wells follow.

	As of June 30, 2007
	Gross		Net
Natural Gas		167		63.5
Crude Oil		171		73.1
Total		338		136.6

Drilling Activity

The following table sets forth our drilling activity.

	Year Ended June 30, 2007				Period from Inception July 25, 2005 Through June 30, 2006
	Gross		Net		Gross		Net
Productive
Development		19.0		14.6		8.0		6.8
Exploratory		5.0		2.8		—		—
Total		24.0		17.4		8.0		6.8
Dry
Development		8.0		8.0		2.0		1.5
Exploratory		8.0		3.6		—		—
Total		16.0		11.6		2.0		1.5

As of June 30, 2007, 8 gross wells, representing approximately 5.3 net wells, were being drilled or awaiting completion.

Acreage

Working interests in developed and undeveloped acreage follow.

	June 30, 2007
	Developed Acres				Undeveloped Acres
	Gross		Net		Gross		Net
Onshore		63,484		31,455		127,881		71,610

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	June 30, 2007
	Developed Acres				Undeveloped Acres
	Gross		Net		Gross		Net
Offshore		311,899		99,780		174,053		71,737
Total		375,383		131,235		301,934		143,347

The following table summarizes potential expiration of our onshore and offshore undeveloped acreage.

	June 30,
	2008				2009				2010
	Gross		Net		Gross		Net		Gross		Net
Onshore		5,735		1,601		6,988		2,707		3,363		2,182
Offshore		43,035		15,588		60,624		30,309		13,132		5,631
Total		48,770		17,189		67,612		33,016		16,495		7,813

Capital Expenditures

Our capital expenditures follow.

	Year Ended June 30, 2007		Period from Inception July 25, 2005 Through June 30, 2006
	(In Thousands)
Oil and Gas Activities
Development	$	362,219	$	18,002
Exploration		67,140		—
Acquisitions		717,618		448,374
Other Property and Equipment		2,468		1,701
Total	$	1,149,445	$	468,077

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Oil and Gas Production and Prices

Our average daily production represents our net ownership and includes royalty interests and net profit interests owned by us. Our average daily production and average sales prices follow.

	Year Ended June 30, 2007		Period from Inception July 25, 2005 Through June 30, 2006
Sales Volumes per Day
Natural gas (MMcf)		50.3		27.9
Crude oil (MBbls)		7.8		5.1
Total (MBOE)		16.2		9.7
Average Sales Price
Natural gas per Mcf	$	7.13	$	6.48
Hedge gain per Mcf		0.90		0.86
Total natural gas per Mcf	$	8.03	$	7.34
Crude oil per Bbl	$	62.33	$	66.64
Hedge gain (loss) per Bbl		5.60		(1.56	)
Total crude oil per Bbl	$	67.93	$	65.08
Sales price per BOE	$	52.23	$	53.35
Hedge gain per BOE		5.48		1.67
Total sales price per BOE	$	57.71	$	55.02

Production Unit Costs

Our production unit costs follow. Production costs include production taxes and lease operating expense.

	Year Ended June 30, 2007		Period from Inception July 25, 2005 Through June 30, 2006
Average Costs per BOE
Production costs
Lease operating expense
Workover expense	$	1.40	$	0.19
Insurance expense		2.14		0.17
Other lease operating expense		8.12		11.20
Production taxes		0.61		0.10
	$	12.27	$	11.66
Depreciation, depletion and amortization rates	$	24.68	$	23.78

Reserves

The following estimates of our net proved crude oil and natural gas reserves, which are located entirely within the United States of America, are based on evaluations prepared by third-party reservoir engineers. These reserves have been prepared in accordance with Securities and Exchange Commission (“SEC”) Regulations. These reserves have been reduced for royalty interests owned by others.

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	June 30, 2007
	Proved Developed Producing		Proved Developed Non-Producing		Total Proved Developed		Proved Undeveloped		Total Proved Reserves
Crude oil (MBbls)		10,409		10,569		20,978		9,362		30,340
Natural gas (MMcf)		53,272		43,479		96,751		55,081		151,832
Total (MBOE)		19,288		17,815		37,103		18,542		55,645
PV-10 (in thousands)(1)	$	707,922	$	524,145	$	1,232,067	$	366,566	$	1,598,633

(1) PV-10 reflects the present value of our estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of June 30, 2007) without giving effect to non-property related expenses such as general and administrative expenses, debt service, DD&A expense and discounted at 10 percent per year before income taxes.

Miller and Lents, Ltd., Netherland, Sewell & Associates, Inc. and Ryder Scott Company, L.P., independent oil and gas consultants, have prepared the estimates of proved of crude oil and natural gas reserves attributable to our net interests in oil and gas properties as of June 30, 2007. For further information on reserves, including information on future net cash flows and the standardized measure of discounted future net cash flows, see “Financial Statements and Supplementary Financial Information.”

Item 3. Legal Proceedings

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

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

No matters were submitted to a vote of our security holders during the fourth quarter of fiscal 2007.

Executive Officers of the Registrant

The following table sets forth the names, ages, and positions of each of our officers.

Name	Age	Position	Since
John D. Schiller, Jr.	48	Chairman and Chief Executive Officer	July 2005
Steven A. Weyel	53	Director, President and Chief Operating Officer	July 2005
David West Griffin	46	Director, Chief Financial Officer	July 2005
Ben Marchive	60	Senior Vice President, Operations	April 2006
Stewart Lawrence	46	Vice President of Investor Relations and Communications	March 2007
Hugh A. Menown	49	Vice President and Chief Accounting Officer	May 2007
Steve Nelson	47	Vice President of Drilling and Production	April 2006

John D. Schiller, Jr. Mr. Schiller is our Chairman and Chief Executive Officer and has been since our inception. Between December 2004 and November 2005, Mr. Schiller acted as interim chief executive officer of Particle Drilling, Inc. Between December 2003 and December 2004, Mr. Schiller pursued personal interests and private investment opportunities. From April 2003 to December 2003, Mr. Schiller served as Vice President, Exploration & Production, for Devon Energy with responsibility for domestic and international activities. Before joining Devon Energy, Mr. Schiller was Executive Vice President, Exploration & Production, for Ocean Energy, Inc. from 1999 to April 2003, with responsibility for Ocean’s worldwide exploration, production and drilling activities. Mr. Schiller joined Ocean Energy from Seagull Energy, where he served as Senior Vice President of Operations, prior to the merger of the two companies in March of 1999. From 1985 to 1998, Mr. Schiller served in various positions with Burlington Resources, including Engineering and Production Manager of the Gulf of Mexico Division and Corporate Acquisition Manager. From 1981 to 1985, Mr. Schiller was a staff engineer at Superior Oil. Mr. Schiller serves on the Board of Directors of Particle Drilling, Inc., a development stage oil and gas services company. Mr. Schiller also serves on the board of the Escape

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Family Resource Center, a charitable organization. Mr. Schiller is a charter member of the Texas A&M Petroleum Engineering Industry Board. Mr. Schiller graduated with honors from Texas A&M University with a Bachelor of Science in Petroleum Engineering in 1981.

Steven A. Weyel Mr. Weyel is our President and Chief Operating Officer and has been since our inception. Mr. Weyel is co-founder and was most recently Principal and President/COO of EnerVen LLC, a company developing and supporting strategic ventures in the emerging energy industry, which company was formed in September 2002. In August 2005, Mr. Weyel sold his membership interests and resigned his positions in EnerVen LLC to devote full time and efforts to Energy XXI. From 1999 to 2002, Mr. Weyel was President and COO of InterGen North America, a Shell-Bechtel joint venture in the merchant gas and power business. From 1994 to 1999, Mr. Weyel was with Dynegy Corporation, previously known as Natural Gas Clearinghouse and NGC Corporation, where he served in various executive leadership positions, including Executive Vice President — Integrated Energy and Senior Vice President — Power Development. Mr. Weyel has a broad range of experience in the international oil service sector, including ownership of his own firm, Resource Technology Corporation, from 1983 to 1994, where he identified a new market opportunity based on evolving technology, and created the global engineering leader in onsite energy commodity reserves evaluation. From 1976 to 1983, Mr. Weyel worked with Baker Eastern S.A. (Baker-Hughes), in numerous strategic growth roles including Managing Director for the Western Hemisphere. Mr. Weyel also served with Mr. Schiller on the Board of Directors of Particle Drilling until his resignation on August 7, 2007. Mr. Weyel received his Masters in Business Administration from the University of Texas at Austin in 1989. Mr. Weyel graduated from Texas A&M University with a Bachelor of Science in Industrial Distribution in 1976.

David West Griffin Mr. Griffin is our Chief Financial Officer and has been since our inception. Prior to inception, Mr. Griffin spent his time focusing on the formation of the company. From January 2004 to December 2004, Mr. Griffin was the Chief Financial Officer of Alon USA, a refining and marketing company. From April 2002 to January 2004, Mr. Griffin owned his own turn-around consulting business, Energy Asset Management. From 1996 to April 2002, Mr. Griffin served in various positions with InterGen, including as Chief Financial Officer for InterGen’s North American business and supervisor of financing of all of InterGen’s Latin American projects. From 1993 to 1996, Mr. Griffin worked in the Project Finance Advisory Group of UBS. From 1985 to 1993, Mr. Griffin served in various positions with Bankers Trust Company. Mr. Griffin graduated Magna Cum Laude from Dartmouth College in 1983 and received his Masters in Business Administration from Tuck Business School in 1985.

Ben Marchive Mr. Marchive is our Senior Vice President, Operations. He has 28 years of experience in the oil and gas industry. He began his career with Superior Oil Company and gained extensive knowledge of offshore drilling, completion and production operations. He has since held management positions with Great Southern Oil & Gas, Kerr-McGee Corporation and most recently Ocean Energy, Inc. During his fourteen year tenure at Kerr-McGee, Ben managed all disciplines of engineering dealing with drilling, production operations, completions and reserve determination for the offshore division. In February 1999 Ben joined Ocean Energy, Inc. where he served as Vice President, Production North America. In this capacity, he was responsible for all Production Operations for North America Land and Offshore until his retirement in July 2003. Ben joined the company in April 2006. He is a member of the Society of Petroleum Engineers, American Petroleum Institute and American Association of Drilling Engineers. Mr. Marchive is a 1977 graduate of Louisiana State University with a Bachelor of Science degree in Petroleum Engineering.

Stewart Lawrence Mr. Lawrence is our Vice President of Investor Relations and Communications. From September 2001 to March 2007, he was Manager of Investor Relations for Anadarko Petroleum Corporation. From 1996 to 2001, Mr. Lawrence was responsible for investor relations and other communications functions at MCN Energy Group, a diversified energy company that was acquired in 2001 by DTE Energy Company. Mr. Lawrence graduated from the University of Houston with a BA in journalism in 1987 and a Masters in Business Administration in 1995.

Hugh A. Menown Mr. Menown is our Vice President and Chief Accounting Officer. He has more than 27 years of experience in mergers and acquisitions, auditing and managerial finance, and has been performing similar roles at Energy XXI on a consultant basis since August 2006. He previously worked with Quanta Services, Inc. performing due diligence on a number of acquisitions as well as serving as chief financial

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officer for two of Quanta’s operating companies. From 1987 to 1999, Menown provided audit and related services for clients at PricewaterhouseCoopers, LLP in the Houston office, where for seven years he was the partner in charge of the transaction services practice providing due diligence, mergers and acquisition advisory and strategic consulting to numerous clients in various industries. Menown serves on the board of directors of Particle Drilling Technologies, Inc. as chairman of the audit committee and a member of the compensation committee. He is a certified public accountant and a 1980 graduate of the University of Missouri — Columbia — with a bachelor’s degree in business administration.

Steve Nelson Mr. Nelson is our Vice President of Drilling and Production. He has over 24 years of experience in the oil and gas business. He was hired from Devon Energy in April 2006 where he was the Manager of Drilling and Operations for Devon’s Western Division. He joined Ocean Energy in April 1999 and prior to the acquisition of Ocean Energy by Devon Energy in May 2003, he was the Production Manager for Ocean Energy’s onshore assets. Previous to that, Mr. Nelson spent 16 years with Kerr McGee’s Gulf of Mexico Division in various operations and supervisory jobs. He graduated with a BS in Petroleum Engineering from the University of Oklahoma in 1983.

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PART II

Item 5.  Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our restricted common stock trades on the AIM Exchange under the symbol “EXXS.” On June 6, 2007 our common stock was admitted to the CREST electronic settlement system, which allows any interested party to trade our unrestricted common stock under the symbol “EXXI.” On August 1, 2007, our common stock was admitted for trading on NASDAQ under the symbol “EXXI.” The following table sets forth, for the periods indicated, the range of the high and low sales prices of our restricted and unrestricted common stock.

	Restricted Common Stock				Unrestricted Common Stock
	High		Low		High		Low
Fiscal 2006
Second Quarter (began trading October 20, 2005)	$	5.35	$	5.12
Third Quarter		5.95		5.24
Fourth Quarter		5.62		5.15
Fiscal 2007
First Quarter		5.15		4.95
Second Quarter		5.15		4.87
Third Quarter		4.96		4.65
Fourth Quarter		6.05		4.78	$	6.44	$	5.25
Fiscal 2008
First Quarter (through September 21, 2007)		6.05		5.15		6.67		4.83

As of September 21, 2007 there were approximately 721 holders of record of our common stock.

We have not paid any cash dividends on our common stock and do not intend to do so in the foreseeable future. We intend to retain our earnings for the future operation and development of our business. In addition, our primary credit facility and the terms of our outstanding subordinated debt prohibit the payment of cash dividends on our common stock.

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Stock Performance Graph

The graph below shows the cumulative total shareholder return assuming the investment of $100 in our common stock. This chart represents our restricted shares from October 2005 through May 2007, then our freely tradable shares from June 2007 through September 21, 2007.

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Item 6. Selected Financial Data

The selected consolidated financial data, set forth below should be read in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the consolidated financial statements and notes to those consolidated financial statements included elsewhere in this report.

	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
	(In Thousands, Except Per Share Amounts)
Income Statement Data
Revenues	$	341,284		$	47,112
Depreciation, Depletion and Amortization (“DD&A”)		145,928			20,357
Operating Income		95,215			11,602
Other Income (Expense) — Net		(58,420	)		(2,933	)
Net Income		24,130			6,942
Basic Earnings per Common Share	$	0.29		$	0.14
Diluted Earnings per Common Share		0.29			0.12
Cash Flows Data
Provided by (Used in)
Operating Activities	$	275,397		$	12,068
Investing Activities
Acquisitions		(717,618	)		(448,374	)
Capital expenditures		(431,827	)		(19,703	)
Other		1,955			(12,593	)
Total Investing Activities		(1,147,490	)		(480,670	)
Financing Activities		829,488			530,991
Increase (Decrease) in Cash and Cash Equivalents	$	(42,605	)	$	62,389

	June 30, 2007		June 30, 2006
	(In Thousands)
Balance Sheet Data
Total Assets	$	1,648,442	$	643,971
Long-term Debt Including Current Maturities		1,051,019		209,648
Stockholders’ Equity		397,126		352,709
Common Shares Outstanding		84,203		80,645

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	Quarter Ended												Year Ended June 30, 2007
	June 30, 2006		Sept. 30, 2006		Dec. 31, 2006			March 31, 2007			June 30, 2007
Revenues	$	47,112	$	65,817	$	79,143		$	77,608		$	118,716	$	341,284
Lease operating expense
Insurance expense		144		2,662		2,653			4,866			2,489		12,670
Workover expense		166		1,322		(495	)		1,910			5,532		8,269
Other production costs		9,592		10,697		10,629			9,575			17,145		48,046
Total lease operating expense		9,902		14,681		12,787			16,351			25,166		68,985
Production taxes		84		811		407			1,691			686		3,595
DD&A		20,317		27,744		31,711			28,600			57,873		145,928
General and administrative		2,752		5,018		5,573			5,733			10,183		26,507
Sales volumes per day
Gas (MMcf)		27.9		47.1		52.1			42.1			60.0		50.3
Oil (MBbls)		5.1		5.9		7.0			7.5			10.9		7.8
Total (MBOE)		9.7		13.8		15.7			14.5			20.9		16.2
Average sales price
Gas per Mcf	$	6.48	$	6.28	$	6.67		$	7.77		$	7.78	$	7.13
Oil per Bbl		66.64		67.16		56.77			56.24			67.46		62.33
Hedge gain per BOE		1.67		1.68		7.19			7.95			5.03		5.48
Total realized per BOE		55.02		52.03		54.71			59.54			62.53		57.71
Per BOE
Lease operating expense
Insurance expense	$	0.17	$	2.10	$	1.83		$	3.73		$	1.31	$	2.14
Workover expense		0.19		1.04		(0.34	)		1.47			2.91		1.40
Other production costs		11.20		8.46		7.35			7.34			9.03		8.12
Total lease operating expense		11.56		11.60		8.84			12.54			13.25		11.66
Production taxes		0.10		0.64		0.28			1.30			0.36		0.61
DD&A		23.73		21.93		21.92			21.94			30.48		24.68
General and administrative		3.21		3.97		3.85			4.40			5.37		4.48
Other		0.87		0.14		0.02			(0.52	)		0.82		0.18
Operating income		15.55		13.75		19.80			19.88			12.25		16.10

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this annual report. The following discussion includes forward looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to those discussed under “Item 1A Risk Factors.”

General

We are an independent energy company engaged in the acquisition, development, exploration and production of oil and natural gas reserves, all of which are currently in the United States Gulf Coast and the Gulf of Mexico. Since our incorporation in July 2005, we have completed three major acquisitions of oil and natural gas properties, the most recent of which closed on June 8, 2007 when we acquired certain oil and natural gas properties in the Gulf of Mexico in the Pogo Acquisition. Our first and second major acquisitions of oil and natural gas properties from Marlin and Castex closed on April 4, 2006 and July 28, 2006, respectively.

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Our exploration and production activities commenced in April 2006 upon our acquisition of Marlin and its Gulf of Mexico assets consisting of working interests in 34 oil and gas fields with 108 producing wells. In July 2006, we acquired additional oil and gas working interests in 21 onshore and inland water Louisiana Gulf Coast fields from Castex. Our average daily production for the three months ended June 30, 2007 was approximately 20.9 MBOE/D, which included one month of production from the Pogo Acquisition.

Results of Operations

Year Ended June 30, 2007 Compared With the Period from Inception (July 25, 2005) through June 30, 2006 (“Period Ended June 30, 2006”).

Our consolidated net income increased to $24.1 million or $0.29 basic earnings per common share (“per share”) in fiscal 2007 primarily due to higher commodity prices and higher production volumes. Below is a discussion of prices, volumes and revenue variances.

Price and Volume Variances

	Year/Period Ended June 30,
	2007		2006		Increase		Percent Increase			Increase
										(In Thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)	$	67.93	$	65.08	$	2.85		4.4	%	$	8,128
Natural gas sales prices (per MCF)		8.03		7.34		0.69		9.4	%		12,675
Total price variance											20,803
Volume Variance
Crude oil sales volumes (MBbls)		2,852		446		2,406		539.5	%		156,565
Natural gas sales volumes (MMCF)		18,370		2,459		15,911		647.1	%		116,804
Total volume variance											273,369
Total variance										$	294,172

(1) Commodity prices include hedging gains and losses.

Revenue Variances

	Year/Period Ended June 30,
	2007		2006		Increase		Percent Increase
	(In Thousands)
Crude oil	$	193,749	$	29,056	$	164,693		566.8	%
Natural gas		147,535		18,056		129,479		717.1	%
Total revenues	$	341,284	$	47,112	$	294,172		624.4	%

Revenues

Our consolidated revenues increased $294.2 million in fiscal 2007. Higher revenues were primarily due to higher commodity prices and higher crude oil and natural gas production volumes, resulting in increased revenues of $20.8 million and $273.4 million, respectively. 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 commodity prices contributed $20.8 million to the increase in revenues in fiscal 2007. Average natural gas prices, including a $0.90 realized gain per MCF related to hedging activities, increased $0.69 per MCF during

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fiscal 2007, resulting in increased revenues of $12.7 million. Average crude oil prices, including a $5.60 realized gain per barrel related to hedging activities, increased $2.85 per barrel in fiscal 2007, resulting in increased revenues of $8.1 million. Commodity prices are affected by many factors that are outside of our control. Therefore, commodity prices we received during fiscal 2007 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time would result in reduced cash from operating activities potentially causing us to expend less on our capital program. Lower spending on our capital program could result in a reduction of the amount of production volumes we are able to produce. We cannot accurately predict future commodity prices, and cannot be certain whether these events will occur.

Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Higher sales volumes in fiscal 2007 resulted in increased revenues of $273.4 million. Crude oil sales volumes increased 2,406 MBbls in fiscal 2007, resulting in increased revenues of $156.6 million. Natural gas sales volumes increased 15,911 MMCF in fiscal 2007, resulting in increased revenues of $116.8 million. The increase in crude oil and natural gas sales volumes in fiscal 2007 was primarily due to our acquisitions and our exploration and development programs.

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

	Year/Period Ended June 30,
	2007						2006						Increase (Decrease) Amount
	Amount			Per BOE			Amount			Per BOE
	(In Thousands Except Per Unit Amounts)
Costs and expenses
Lease operating expense
Workover expense	$	8,269		$	1.40		$	166		$	0.19		$	8,103
Insurance expense		12,670			2.14			144			0.17			12,526
Other lease operating expense		48,046			8.12			9,592			11.20			38,454
Total lease operating expense		68,985			11.66			9,902			11.56			59,083
Production taxes		3,595			0.61			84			0.10			3,511
DD&A		145,928			24.68			20,357			23.78			125,571
Accretion of asset retirement obligation		3,991			0.68			738			0.86			3,253
General and administrative expense		26,507			4.48			4,361			5.09			22,146
Loss (gain) on derivative financial instruments		(2,937	)		(0.50	)		68			0.08			(3,005	)
Total costs and expenses	$	246,069		$	41.61		$	35,510		$	41.47		$	210,559
Other (income) expense
Interest income	$	(1,910	)	$	(0.32	)	$	(5,000	)	$	(5.84	)	$	3,090
Interest expense		60,330			10.20			7,933			9.26			52,397
Total other (income) expense	$	58,420		$	9.88		$	2,933		$	3.42		$	55,487

Costs and expenses increased $210.6 million in fiscal 2007. This increase in costs and expenses was primarily due to the items discussed below.

DD&A expense increased $125.6 million primarily due to increased production from acquisitions and drilling ($120.3 million), coupled with a higher DD&A rate ($5.3 million). Lease operating expense increased

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$59.1 million in fiscal 2007 compared to fiscal 2006. This increase is primarily due to higher well operating expenses, which include direct expenses incurred to operate our wells and equipment on producing leases. Well operating expenses were higher primarily due to an increase in producing leases from acquisitions and from our exploration and development programs, increased fuel and electricity expenses and higher repair and maintenance expenses. The higher workover activity and higher windstorm insurance is also primarily due to an increase in producing leases from acquisitions.

Production taxes and transportation increased $3.5 million primarily due to higher production taxes resulting from higher crude oil and natural gas revenues. General and administrative expense increased $22.1 million primarily due an increase in personnel and related costs as a result of acquisitions and increased legal and auditing fees as a result of increased document filings.

Other (income) expense increased $55.5 million in fiscal 2007. This increase was primarily due to the items discussed below.

Interest income decreased $3.1 million due to the decrease in cash and cash equivalents. Interest expense increased $52.4 million due to the additional borrowings required to fund our acquisition and capital expenditure programs.

Income Tax Expense

Income tax expense increased $10.9 million in fiscal 2007 compared to fiscal 2006, primarily due to an increase in income before income taxes of $28.1 million and to an increase in the effective income tax rate from 20 percent to 34 percent.

Liquidity

Overview

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

• drilling and completing new natural gas and oil wells;

• 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.

We have incurred substantial indebtedness in connection with our acquisitions, including the $750 million senior notes offering we completed on June 8, 2007 to fund the Pogo Acquisition and to repay our second lien revolving credit facility. At June 30, 2007, we had $1,051 million of indebtedness outstanding, consisting of $750 million of notes offered and sold, $292 million under our first lien revolving credit facility, $8.4 million in put financings and $0.6 million in capital lease obligations. We expect to fund our operations and capital expenditures and satisfy our debt service obligations through operating cash flow and borrowings under our first lien revolving credit facility. Expansion capital expenditures are directly related to new development opportunities and growth of our reserve base and production at attractive returns.

Future Commitments

The table below provides estimates of the timing of future payments that, as of June 30, 2007, we are obligated to make. We expect to fund these contractual obligations with cash generated from operations.

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	Payments Due by Period
	Total		Less Than 1 Year		1 - 3 Years		4 - 5 Years		After 5 Years
	(In thousands)
Contractual Obligations
Total debt(1)	$	1,051,019	$	5,508	$	3,435	$	292,076	$	750,000
Interest on long-term debt(1)		532,353		97,074		193,189		170,172		71,918
Operating leases(2)		13,569		1,294		2,588		2,588		7,099
Drilling rig commitments(2)		8,942		8,942		—		—		—
Performance bonds(2)		43,150		43,150		—		—		—
Letters of credit(2)		5,500		5,500		—		—		—
Other		2,263		2,263		—		—		—
Total contractual obligations		1,656,796		163,731		199,212		464,836		829,017
Other Obligations
Asset retirement obligations(3)		75,829		12,465		7,648		5,210		50,506
Total obligations	$	1,732,625	$	176,196	$	206,860	$	470,046	$	879,523

(1) See Note 4 of Notes to Consolidated Financial Statements for details of total debt.

(2) See Note 13 of Notes to Consolidated Financial Statements for discussion of these commitments.

(3) See Note 5 of Notes to Consolidated Financial Statements for details of asset retirement obligations.

Capital Resources

The fiscal 2008 capital budget, excluding acquisitions, for the exploration and development drilling program is approximately $260 million. We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, and future acquisitions from cash flows from our operations and borrowings under our credit facility. If an acquisition opportunity arises, we may also access public markets to issue additional debt and/or equity securities. Cash flows from operations were used primarily to fund acquisitions and exploration and development expenditures during the year ended June 30, 2007. In June 2007, we also completed our $750 million high yield facility which enabled us to pay off our second lien facility and help fund the Pogo Acquisition. At June 30, 2007 we had a working capital surplus of $9.0 million.

Net cash provided by operating activities in fiscal 2007 increased $263.3 million from the period from inception (July 25, 2005) through June 30, 2006 (the “2006 period”) primarily due to higher production volumes and higher commodity prices (including hedging gains) partially offset by higher costs and expenses, excluding non—cash expenses. Key drivers of net operating cash flows are commodity prices, production volumes and costs and expenses. Average natural gas prices increased 9 percent over the 2006 period. Crude oil prices increased four percent over the 2006 period. Natural gas volumes and crude oil volumes increased 647 percent and 540 percent over the 2006 period, respectively.

The increase in net cash provided by operating activities resulting from higher commodity prices and higher production volumes was partially offset by higher costs and expenses. In fiscal 2007, costs and expenses that affect net operating cash provided by operating activities primarily include lease operating expense, production taxes and transportation, and general and administrative expense. These costs and expenses increased $84.7 million over the 2006 period. Lease operating expense and general and administrative expense represented the largest increases in these costs. Lease operating expense includes well operating expenses, which are expenses incurred to operate our wells and equipment on operating leases.

Generally, producing natural gas and crude oil reservoirs have declining production rates. Production rates are impacted by numerous factors, including but not limited to, geological, geophysical and engineering matters, production curtailments and restrictions, weather, market demands and our ability to replace depleting reserves. Our inability to adequately replace reserves could result in a decline in production volumes, one of the key drivers of generating net operating cash flows. Our reserve replacement ratio, including acquisitions, for the fiscal year ended June 30, 2007 was 625 percent. Results for any year are a function of the success of

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our drilling program and acquisitions. While program results are difficult to predict, our current drilling inventory provides us opportunities to replace our production in fiscal 2008.

Commodity Prices

Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain that way in the future. Commodity prices are affected by numerous factors, including but not limited to, supply, market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future crude oil and natural gas prices, and therefore, we cannot determine what impact increases or decreases in production volumes will have on future revenues or net operating cash flows.

Potential Acquisitions

While it is difficult to predict future plans with respect to acquisitions, we actively seek acquisition opportunities that build upon our existing core assets. Acquisitions play a large role in this industry’s consolidation and a strategic part of our business plan. Depending on the commodity price environment at any given time, the property acquisition market can be extremely competitive.

Critical Accounting Policies

We have identified the following policies as critical to the understanding of our results of operations. This is not a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States (GAAP), with no need for management’s judgment in selecting in their application. There are also areas in which management’s judgment in selecting any available alternative would not produce a materially different result. However, certain accounting policies are important to the portrayal of our financial condition and results of operations and require management’s most subjective or complex judgments. In applying those policies, management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. Our critical accounting policies and estimates are set forth below. Certain of these accounting policies and estimates are particularly sensitive because of their complexity and the possibility that future events affecting them may differ materially from our management’s current judgment.

Use of Estimates. The preparation of financial statements in conformity with 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 financial statements and the reported amounts of revenues and expenses during the reporting period.

Proved Oil and Gas Reserves. Proved oil and gas reserves are defined by the SEC as those volumes of oil and gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered from existing wells with existing equipment and operating methods. Although our external engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires the engineers to make a number of assumptions based on professional judgment. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions in reserve quantities. Reserve revisions will inherently lead to adjustments of DD&A rates. We cannot predict the types of reserve revisions that will be required in future periods.

Oil and Gas Properties. We use the full cost method of accounting for exploration and development activities as defined by the United States Securities and Exchange Commission, (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or

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similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

Acquisition costs are allocated between proved and unproved properties based on their relative fair value. Determination of fair value includes estimates of discounted future net revenues related to proved and probable reserves.

Oil and gas properties include costs of unproved properties. Unproved properties related to significant acquisitions are excluded from the depreciation, depletion and amortization (“DD&A”) base until it is determined that proved reserves can be assigned to such properties or until we have made evaluation that impairment has incurred.

We capitalize interest on expenditures made in connection with the exploration and development of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. We have not capitalized any interest during any of the periods presented.

Oil and gas properties included in the DD&A base are amortized using the unit-of-production method based on production estimates of proved reserve quantities. In addition to costs associated with evaluated properties, the DD&A base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, that have not yet been capitalized as asset retirement costs.

Under the full cost method of accounting, we are required to periodically perform a “ceiling test” which determines a limit on the book value of our oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10 percent, net of related tax effects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. Future net cash flows are based on period-end commodity prices and exclude future cash outflows related to estimated abandonment costs. We did not have a ceiling test impairment during year/period ended June 30, 2007 or 2006.

Asset Retirement Obligations. Our investment in oil and gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. These costs are recorded as provided in the Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. The present value of the future costs are added to the capitalized cost of our oil and gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that are difficult to predict.

Derivative Instruments. We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Such derivatives are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended. Gains or losses resulting from transactions designated as hedges, recorded at market value, are deferred and recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of income as the physical production hedged by the contracts is delivered. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings.

The net cash flows related to any recognized gains or losses associated with these hedges are reported as oil and gas revenue and presented in cash flow from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contract is delivered.

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The conditions to be met for a derivative instrument to qualify as a cash flow hedge are the following: (i) the item to be hedged exposes us to price risk; (ii) the derivative reduces the risk exposure and is designated as a hedge at the time the derivative contract is entered into; (iii) at the inception of the hedge and throughout the hedge period there is a high correlation of changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.

When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on sale or settlement of the underlying item. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if the correlation no longer exists, the gain or loss on the derivative is recognized in income to the extent the future results have not been offset by the effects of price changes on the hedged item since the inception of the hedge.

Price volatility within a measured month is the primary factor affecting the analysis of effectiveness of our oil and gas derivatives. Volatility can reduce the correlation between the hedge settlement price and the price received for physical deliveries. Secondary factors contributing to changes in pricing differentials include changes in the basis differential which is the difference between the locally indexed price received for daily physical deliveries of the hedged quantities and the index price used in hedge settlement, as well as changes in grade and quality factors of the hedged oil and gas production that would further impact the price received for physical deliveries.

The following table summarizes our fair value of derivative contracts sensitivities to changes in oil and gas prices:

	June 30, 2007						June 30, 2006
	Oil (Bbl)			Gas (MMbtu)			Oil (Bbl)			Gas (MMbtu)
Average prices used in determining fair value	$	71.94		$	8.23		$	74.61		$	8.71
Decrease in fair value of derivative contracts resulting from a 10% increase in oil or natural gas prices (in thousands)(1)(2)	$	(30,500	)	$	(19,100	)	$	(18,625	)	$	(11,671	)

(1) Subsequent increases in oil and natural gas prices would not necessarily have the same impact on fair value due to the nature of some of our derivative contracts.

(2) Substantially all of the change in fair value would be deferred in Other Comprehensive Income (OCI). In addition, increases in prices would have a positive impact on our oil and natural gas revenues.

Net income would have increased (decreased) for the period from July 25, 2005 (inception) to June 30, 2006 and for the year ended June 30, 2007 by ($4.7 million) and $7.8 million, respectively, if our crude oil and natural gas hedges did not qualify as cash flow hedges under SFAS No. 133.

Income Taxes. We account for income taxes in accordance with SFAS No. 109 Accounting for Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion.

When recording income tax expense, certain estimates are required by management due to timing and the impact of future events on when income tax expenses and benefits are recognized by us. We may have to

33

periodically evaluate any tax operating loss and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized in our financial statements.

New Accounting Standards

Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued Interpretation No. 48 (“FIN 48”) Accounting for Uncertainty in Income Taxes which is an interpretation of SFAS No. 109 Accounting for Income Taxes. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We believe that FIN 48 may have an impact on our financial statements when there is uncertainty regarding a certain tax position taken or to be taken. In such a situation, the provisions of FIN 48 will be utilized to evaluate measure and record the tax position, as appropriate. We will adopt the provisions of FIN 48 effective July 1, 2007. We are currently evaluating the impact of FIN 48.

Accounting for Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157 Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The provisions of SFAS No. 157 will be applied prospectively as of the beginning of the fiscal year in which it is initially applied except for, among other items, a financial instrument that was measured at fair value at initial recognition under Statement 133 using the transaction price in accordance with the guidance in footnote 3 of Issue 02-3 prior to initial application of SFAS No. 157. We are currently evaluating the impact of SFAS No. 157 and whether to early adopt its provisions.

Quantifying Misstatements. In September 2006, the SEC staff issued SEC Staff Accounting Bulletin (“SAB”) Topic 1N Financial Statements — Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 addresses how a registrant should quantify the effect of an error on the financial statements. The SEC staff concludes in SAB 108 that a dual approach should be used to compute the amount of a misstatement. Specifically, the amount should be computed using both the “rollover” (current year income statement perspective) and “iron curtain” (year-end balance sheet perspective) methods. SAB 108 also permits public companies to report the cumulative effect of the new policy as an adjustment to opening retained earnings, whereas under SFAS No. 154, Accounting Changes and Error Corrections, changes in accounting policy generally are accounted for using retrospective application. SAB 108 will not have a material impact on our consolidated financial statements.

Accounting for Registration Payment Arrangements. In December 2006, the FASB issued FASB Staff Position (“FSP”) EITF 00-19-2, Accounting for Registration Payment Arrangements. This FSP specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies. This FSP further clarifies that a financial instrument subject to a registration payment arrangement should be accounted for in accordance with other applicable GAAP without regard to the contingent obligation to transfer consideration pursuant to the registration payment arrangement. This FSP amends various authoritative literature notably SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and SFAS Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.

This FSP is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to December 21, 2006, the guidance in the FSP is effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. This FSP has no impact on our consolidated financial statements for the period from inception (July 25, 2005) to June 36, 2006 or for the year ended June 30, 2007.

34

Accounting for the Fair Value Option for Financial Assets and Financial Liabilities. In February 2007, the FASB issued SFAS No. 159 The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits companies to choose to measure certain financial instruments and certain other items at fair value. SFAS No. 159 requires that we report unrealized gains and losses on items for which we elect the fair value option in earnings. We are required to adopt the provisions of SFAS No. 159 beginning with our first fiscal quarter in fiscal 2009, although the FASB permits earlier adoption. We are currently evaluating the impact of SFAS No. 159 and whether to early adopt its provisions.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

Market-Sensitive Instruments and Risk Management

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

Commodity Price Risk

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

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

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

The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements.

Disclosure of Limitations

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

Interest Rate Risk

On June 26, 2006, we entered into interest rate costless collar to mitigate the risk of loss due to changes in interest rates. The dollar amount hedged was $75 million with the interest rate collar being 5.45 percent to 5.75 percent. At June 30, 2007, the fair value of this instrument which was designated as a financial hedge, prior to the impact of federal income tax, was a loss of $0.5 million.

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

35

Item 8.  Financial Statements and Supplementary Financial Information

	Page
Management’s Report on Internal Control over Financial Reporting		37
Report of Independent Registered Public Accounting Firm		38
Consolidated Financial Statements
Consolidated Balance Sheets		39
Consolidated Statements of Income		40
Consolidated Statement of Stockholders’ Equity		41
Consolidated Statements of Cash Flows		42
Notes to Consolidated Financial Statements		43

36

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

• Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Our management assessed the effectiveness of our internal control over financial reporting as of June 30, 2007. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment, management has concluded that, as of June 30, 2007, our internal control over financial reporting was effective based on those criteria.

37

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Energy XXI (Bermuda) Limited

We have audited the accompanying consolidated balance sheets of Energy XXI (Bermuda) Limited (a Bermuda Corporation) and subsidiaries (the “Company”) as of June 30, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity and comprehensive income and cash flows for the year ended June 30, 2007 and for the period from inception (July 25, 2005) through June 30, 2006. These consolidated financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy XXI (Bermuda) Limited and subsidiaries as of June 30, 2007 and 2006, and the consolidated results of its operations and its cash flows for the year ended June 30, 2007 and for the period from inception (July 25, 2005) through June 30, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas
September 24, 2007

38

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Information)

	June 30,
	2007		2006
ASSETS
Current Assets
Cash and cash equivalents	$	19,784	$	62,389
Accounts receivable
Oil and natural gas sales		55,763		19,325
Joint interest billings		14,377		11,173
Acquisition		—		14,070
Stock subscription		—		7,326
Insurance and other		958		39,801
Prepaid expenses and other current assets		21,870		9,200
Royalty deposit		2,175		2,175
Derivative financial instruments		17,131		7,752
Total Current Assets		132,058		173,211
Property and Equipment, net of accumulated depreciation, depletion, and amortization
Oil and natural gas properties – full cost method of accounting		1,491,685		447,852
Other property and equipment		3,097		1,569
Total Property and Equipment		1,494,782		449,421
Other Assets
Deposit and acquisition costs		—		10,025
Derivative financial instruments		616		5,856
Deferred income taxes		—		1,780
Debt issuance costs, net of accumulated amortization		20,986		3,678
Total Other Assets		21,602		21,339
Total Assets	$	1,648,442	$	643,971
LIABILITIES
Current Liabilities
Accounts payable	$	79,563	$	23,281
Advances from joint interest partners		2,026		6,211
Accrued liabilities		33,411		11,463
Income and franchise taxes payable		48		913
Deferred income taxes		1,044		143
Derivative financial instruments		1,480		948
Current maturities of long-term debt		5,508		9,584
Total Current Liabilities		123,080		52,543
Long-term debt, less current maturities		1,045,511		200,064
Deferred income taxes		14,788		—
Asset retirement obligations		63,364		37,844
Derivative financial instruments		4,573		590
Other liabilities		—		221
Total Liabilities		1,251,316		291,262
Commitments and Contingencies (Note 13)
Stockholders’ Equity
Preferred stock, $0.01 par value, 2,500,000 shares authorized and no shares issued at June 30, 2007 and 2006		—		—
Common stock, $0.001 par value, 400,000,000 shares authorized and 84,203,444 and 80,645,129 issued and outstanding at June 30, 2007 and 2006, respectively		84		81
Additional paid-in capital		363,206		350,238
Retained earnings		31,072		6,942
Accumulated other comprehensive income (loss), net of tax expense		2,764		(4,552	)
Total Stockholders’ Equity		397,126		352,709
Total Liabilities and Stockholders’ Equity	$	1,648,442	$	643,971

 
 
See accompanying Notes to Consolided Financial Statements

39

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Information)

	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
Revenues
Crude oil sales	$	193,749		$	29,056
Natural gas sales		147,535			18,056
Total Revenues		341,284			47,112
Costs And Expenses
Lease operating expense		68,985			9,902
Production taxes		3,595			84
Depreciation, depletion and amortization		145,928			20,357
Accretion of asset retirement obligation		3,991			738
General and administrative expense		26,507			4,361
Loss (gain) on derivative financial instruments		(2,937	)		68
Total Costs and Expenses		246,069			35,510
Operating Income		95,215			11,602
Other Income (Expense)
Interest income		1,910			5,000
Interest expense		(60,330	)		(7,933	)
Total Other Income (Expense)		(58,420	)		(2,933	)
Income Before Income Taxes		36,795			8,669
Provision For Income Taxes		12,665			1,727
Net Income	$	24,130		$	6,942
Earnings Per Share
Basic	$	0.29		$	0.14
Diluted	$	0.29		$	0.12
Weighted Average Number Of Common Stock Outstanding
Basic		83,959			49,839
Diluted		83,959			58,475

 
 
See accompanying Notes to Consolided Financial Statements

40

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In Thousands)

	Shares		Common Stock		Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Inception, July 25, 2005		—	$	—	$	—		$	—	$	—		$	—
Common stock issued		62,500		63		277,676								277,739
Warrants exercised		18,145		18		72,562								72,580
Comprehensive income:
Net income									6,942					6,942
Unrealized loss on derivative financial instruments, net of tax											(4,552	)		(4,552	)
Total comprehensive income														2,390
Balance, June 30, 2006		80,645		81		350,238			6,942		(4,552	)		352,709
Common stock issued - warrants exercised and other		3,558		3		14,037								14,040
Warrants repurchased						(1,069	)							(1,069	)
Comprehensive income:
Net income									24,130					24,130
Unrealized gain on derivative financial instruments, net of tax											7,316			7,316
Total comprehensive income														31,446
Balance, June 30, 2007		84,203	$	84	$	363,206		$	31,072	$	2,764		$	397,126

 
 
See accompanying Notes to Consolided Financial Statements

41

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

	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
Cash Flows From Operating Activities
Net income	$	24,130		$	6,942
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Deferred income tax expense		13,530			814
Change in derivative financial instruments		11,759			1,153
Accretion of asset retirement obligations		3,991			738
Depletion, depreciation, and amortization		145,928			20,357
Write-off of debt issuance costs-net		7,045			494
Changes in operating assets and liabilities
Accounts receivable		16,458			(26,912	)
Prepaid expenses and other current assets		(12,670	)		(5,815	)
Accounts payable and other liabilities		65,226			14,297
Net Cash Provided by Operating Activities		275,397			12,068
Cash Flows From Investing Activities
Acquisitions		(717,618	)		(448,374	)
Capital expenditures		(431,827	)		(19,703	)
Proceeds from the sale of oil and natural gas properties		1,400			—
Escrow deposit		—			(10,025	)
Other		555			(2,568	)
Net Cash Used in Investing Activities		(1,147,490	)		(480,670	)
Cash Flows From Financing Activities
Proceeds from the issuance of common stock		14,040			384,872
Proceeds from long-term debt		1,199,444			206,650
Payments on long-term debt		(349,780	)		(14,150	)
Payments on put financing		(8,794	)		(330	)
Stock issuance costs		—			(22,308	)
Debt issuance costs		(24,353	)		(4,172	)
Repurchase of common stock and other		(1,069	)		(19,571	)
Net Cash Provided by Financing Activities		829,488			530,991
Net Increase (Decrease) In Cash And Cash Equivalents		(42,605	)		62,389
Cash And Cash Equivalents, beginning of year/period		62,389			—
Cash And Cash Equivalents, end of year/period	$	19,784		$	62,389

 
 
See accompanying Notes to Consolided Financial Statements

42

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies

Nature of Operations. Energy XXI (Bermuda) Limited (“Energy XXI”) was incorporated in Bermuda on July 25, 2005. Energy XXI (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company with its principal wholly-owned subsidiary, Energy XXI Gulf Coast, Inc. (“EGC”), headquartered in Houston, Texas. We are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico.

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

Revenue Recognition. We recognize oil and natural gas revenue under the entitlement method of accounting. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices.

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

Business Segment Information. The Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 131 Disclosures about Segments of an Enterprise and Related Information establishes standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses. Separate financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Our operations involve the exploration, development and production of oil and natural gas and are entirely located in the United States of America. We have a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments.

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

Allowance for Doubtful Accounts. We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2007 and 2006, no allowance for doubtful accounts was necessary.

General and Administrative Expense. Under the full cost method of accounting, a portion of our general and administrative expense that is directly identified with our acquisition, exploration and development activities is capitalized as part of oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to directly support those employees that are directly involved in acquisition, exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities. Our capitalized general and administrative expense directly related to our acquisition, exploration and development activities for the year ended June 30, 2007 and for the period from inception (July 25, 2005) through June 30, 2006 was $7.7 million and $1.9 million, respectively.

43

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies  – (continued)

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

Acquisition costs are allocated between proved and unproved properties based on their relative fair value. Determination of fair value includes estimates of discounted future net revenues related to proved and probable reserves.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unproved properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized.

Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method. Other property including, leasehold improvements, office and computer equipment and vehicles which are stated at original cost and depreciated using the straight-line method over the useful life of the assets, which ranges from three to five years.

Ceiling Test. Under the full cost method of accounting, we are required to periodically perform a “ceiling test” which determines a limit on the book value of our oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10 percent, net of related tax effects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. Future net cash flows are based on period-end commodity prices and exclude future cash outflows related to estimated abandonment costs. We did not have a ceiling test impairment during year/period ended June 30, 2007 or 2006.

Capitalized Interest. Interest is capitalized as part of the cost of acquiring assets. Oil and natural gas investments in significant unproved properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs. Capitalized interest cannot exceed gross interest expense. As oil and natural gas costs excluded are transferred to the depreciable base, the associated capitalized interest is also transferred. For the period from inception (July 25, 2005) to June 30, 2006 and for the year ended June 30, 2007, we have not capitalized any interest expense.

Other Property and Equipment. Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years. Repairs and maintenance costs are expensed in the period incurred.

44

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies  – (continued)

Asset Retirement Obligations. Our investment in oil and gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. These costs are recorded as provided in SFAS No. 143, Accounting for Asset Retirement Obligations. The present value of the future costs are added to the capitalized cost of our oil and gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

Debt Issuance Costs. Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the scheduled maturity of the debt utilizing the interest method.

Derivative Instruments. We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Such derivatives are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Gains or losses resulting from transactions designated as cash flow hedges are recorded at market value and are deferred and recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of income as the physical production hedged by the contracts is delivered. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings.

The net cash flows related to any recognized gains or losses associated with cash flow hedges are reported as oil and gas revenue and presented in cash flow from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contract is delivered.

Income Taxes. We account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion.

When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We may have to periodically evaluate any tax operating loss and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized in our consolidated financial statements.

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

Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued Interpretation No. 48 (“FIN 48”) Accounting for Uncertainty in Income Taxes which is an interpretation of SFAS No. 109 Accounting for Income Taxes. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position

45

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies  – (continued)

taken or expected to be taken in a tax return. We believe that FIN 48 may have an impact on our financial statements when there is uncertainty regarding a certain tax position taken or to be taken. In such a situation, the provisions of FIN 48 will be utilized to evaluate measure and record the tax position, as appropriate. We will adopt the provisions of FIN 48 effective July 1, 2007 and are currently evaluating the impact of FIN 48.

Accounting for Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157 Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The provisions of SFAS No. 157 will be applied prospectively as of the beginning of the fiscal year in which it is initially applied except for, among other items, a financial instrument that was measured at fair value at initial recognition under Statement 133 using the transaction price in accordance with the guidance in footnote 3 of Issue 02-3 prior to initial application of SFAS No. 157. We are currently evaluating the impact of SFAS No. 157 and whether to early adopt its provisions.

Quantifying Misstatements. In September 2006, the SEC staff issued SEC Staff Accounting Bulletin (“SAB”) Topic 1N Financial Statements — Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 addresses how a registrant should quantify the effect of an error on the financial statements. The SEC staff concludes in SAB 108 that a dual approach should be used to compute the amount of a misstatement. Specifically, the amount should be computed using both the “rollover” (current year income statement perspective) and “iron curtain” (year-end balance sheet perspective) methods. SAB 108 also permits public companies to report the cumulative effect of the new policy as an adjustment to opening retained earnings, whereas under SFAS No. 154, Accounting Changes and Error Corrections, changes in accounting policy generally are accounted for using retrospective application. SAB 108 will not have a material impact on our consolidated financial statements.

Accounting for Registration Payment Arrangements. In December 2006, the FASB issued FASB Staff Position (“FSP”) EITF 00-19-2, Accounting for Registration Payment Arrangements. This FSP specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies. This FSP further clarifies that a financial instrument subject to a registration payment arrangement should be accounted for in accordance with other applicable GAAP without regard to the contingent obligation to transfer consideration pursuant to the registration payment arrangement. This FSP amends various authoritative literature notably SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and SFAS Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.

This FSP is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to December 21, 2006, the guidance in the FSP is effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. This FSP has no impact on our consolidated financial statements for the period from inception (July 25, 2005) to June 36, 2006 or for the year ended June 30, 2007.

Accounting for the Fair Value Option for Financial Assets and Financial Liabilities. In February 2007, the FASB issued SFAS No. 159 The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits companies to choose to measure certain financial instruments and certain other items at fair value. SFAS No. 159 requires that we report unrealized gains and losses on items for which we elect the fair value option in earnings. We are required to adopt the provisions of SFAS No. 159 beginning with our first

46

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies  – (continued)

fiscal quarter in fiscal 2009, although the FASB permits earlier adoption. We are currently evaluating the impact of SFAS No. 159 and whether to early adopt its provisions.

Note 2 — Acquisitions

Pogo

On April 24, 2007, we announced that we had conditionally agreed to purchase certain oil and natural gas properties in the Gulf of Mexico (the “Pogo Properties”) from Pogo Producing Company (the “Pogo Acquisition.”) The Pogo Acquisition included working interests in 28 oil and gas fields.

On June 8, 2007, we closed the purchase of these properties for $409.8 million net of approximately $7.8 million in preference rights that were exercised and the assumption of $1.8 million of non current liabilities.

Subsequent to closing it was determined that the preference rights related to the South Pass 49 pipeline would not be exercised so we paid an additional $3 million to Pogo which was accrued at June 30, 2007. We are still waiting on the final settlement statement for the properties operation for the period from the effective date (April 1, 2007) to the closing date. The allocation between evaluated properties and unevaluated properties is preliminary.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values on June 8, 2007 (in thousands):

Oil and natural gas properties	$	449,223
Asset retirement obligations		(32,244	)
Other non current liabilities		(1,842	)
Cash paid, including acquisition costs of $461	$	415,137

Castex

On June 7, 2006, we entered into a definitive agreement with a number of sellers (the “Sellers”) to acquire certain oil and natural gas properties in Louisiana (the “Castex Acquisition”). We made a $10 million earnest money deposit and put in place certain commodity hedges in anticipation of closing. The properties comprise interests in approximately 21 fields and approximately 76,000 net acres.

We closed the Castex Acquisition on July 28, 2006 and at the same time entered into a 50/50 exploration agreement with two of the Sellers for 24 months covering an area of mutual interest in south Louisiana (the “Exploration Agreement”). In addition, we entered into a joint development agreement with one of the Sellers that includes the area around Lake Salvador in Louisiana (the “Joint Development Agreement”). Our cash cost of the acquisition was approximately $311.2 million for the reserves and we agreed to provide up to a $31 million carried interest in future wells to be drilled, which has all been funded as of June 30, 2007.

If production from one of the properties acquired exceeds 34 BCFE, a level above the proved reserves we assumed in the acquisition, a production payment of up to 3 BCFE of future production will also be payable to the Sellers beginning in January 2009. We are still waiting for the final settlement statement from Castex related to the operations from the effective date (June 1, 2006) to close.

Lake Salvador Joint Development Agreement: The Joint Development Agreement covers an area of mutual interest (“Lake Salvador AMI”) consisting of approximately 1,680 square miles south of New Orleans, Louisiana. The acreage within the Lake Salvador AMI includes leased, unleased and optioned tracts. We and the Seller party to the Exploration Agreement each have the optional right to participate for a 50 percent interest in acquisitions made by the other party including (1) producing property acquisitions, (2) leases acquired by the exercise of an option to purchase, (3) newly purchased leases or (4) other interest acquired by purchase, farm-in, or otherwise (each an “Acquisition”).

47

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 — Acquisitions  – (continued)

If a party elects to participate in an Acquisition, a model form operating agreement will be executed. The form operating agreement provides for a forfeiture non-participation penalty such that failure to participate in the drilling of an exploratory well results in forfeiture of all rights within the identified prospect area associated with such well. Participation in an Acquisition made within the Lake Salvador AMI is optional. We acquired rights to approximately 1,000 square miles of 3D seismic data within the Lake Salvador AMI and have the commitment to bear 50 percent of an estimated $11 million seismic acquisition cost. As of June 30, 2007, approximately $2.3 million in committed seismic costs remained as an obligation to us.

Exploration Agreement: The Exploration Agreement covers an area of mutual interest (“Exploration AMI”) consisting of approximately 1.5 million acres in southeast Louisiana. The acreage within the Exploration AMI includes leased, unleased, optioned tracts and properties held by production. The producing properties we acquired from the Sellers in the Castex Acquisition are excluded from the provisions of the Exploration AMI. We and the two Sellers party to the Exploration Agreement each have the optional right to participate for a 50 percent interest in Acquisitions made by the other parties. The Exploration AMI is situated adjacent to and west and south of the Lake Salvador AMI.

If a party elects to participate in an Acquisition, a model form operating agreement will be executed. The form operating agreement provides for a forfeiture non-participation penalty of all rights within the identified prospect area (not to exceed 2000 acres) such that failure to participate in the drilling of an exploratory well results in forfeiture of all rights within the identified prospect associated with such well. Participation in an acquisition made within the Exploration AMI and associated wells is optional.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values on July 28, 2006 (in thousands):

Oil and natural gas properties	$	318,024
Asset retirement obligations		(5,518	)
Cash paid, including acquisition costs of $1,362	$	312,506

Total cash consideration of $311.2 million included a $10 million deposit and $25,000 of acquisition costs paid in June 2006.

Marlin

On February 21, 2006, we entered into a definitive agreement with Marlin Energy, L.L.C. (“Marlin”) to acquire 100 percent of the membership interests in Marlin Energy Offshore, L.L.C. and Marlin Texas GP, L.L.C. and the limited partnership interests in Marlin Texas, L.P. (collectively, the “Oil and Gas Assets”) for total cash consideration of approximately $448.4 million, including acquisition costs of $1.6 million. Total cash consideration included an initial purchase price payment of $421 million, working capital payments of $9.8 million, and purchase price adjustments from the contractual effective date of the transaction (January 1, 2006) through the closing date (April 4, 2006) of $16 million. The Oil and Gas Assets represent interests in oil and natural gas production properties and undeveloped acreage in approximately 34 onshore and offshore fields.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values on April 4, 2006 (in thousands):

Net working capital	$	358
Insurance receivable		26,614
Acquisition receivable due from Marlin		14,070
Oil and natural gas properties		443,927
Asset retirement obligations		(36,595	)
Cash paid, including acquisition costs of $1,607	$	448,374

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 — Acquisitions  – (continued)

Pogo and Castex Pro Forma Information (Unaudited)

The following summarized unaudited pro forma financial information for the year ended June 30, 2007 assumes that the Pogo and Castex Acquisitions had occurred on July 1, 2006. These unaudited pro forma financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if we had completed the acquisitions as of July 1, 2006 or the results that will be attained in the future (in thousands except share and per share data).

	Year Ended June 30, 2007
Revenues	$	471,265
Operating Income		88,573
Net Loss		(4,364	)
Loss per Share
Basic	$	(0.05	)
Diluted		(0.05	)

Marlin Pro Forma Information (Unaudited)

The following summarized unaudited pro forma financial information for the period from inception (July 25, 2005) through June 30, 2006 assumes that the Marlin Acquisition had occurred on July 1, 2005. These unaudited pro forma financial results have been prepared for informational purposes only and may not be indicative of the results that would have occurred if we had completed the acquisition as of July 1, 2005 or the results that will be attained in the future (in thousands except share and per share data).

Oil and natural gas revenues	$	157,110
Net loss		(14,909	)
Net loss per share – basic		(0.23	)
Net loss per share – diluted		(0.23	)

Note 3 — Property and Equipment

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

	June 30,
	2007		2006
Oil and gas properties
Proved properties	$	1,412,890	$	417,237
Less: Accumulated depreciation, depletion and amortization		165,186		20,225
Proved properties – net		1,247,704		397,012
Unproved properties		243,981		50,840
Oil and gas properties – net		1,491,685		447,852
Other property and equipment		4,194		1,701
Less: Accumulated depreciation		1,097		132
Other property and equipment – net		3,097		1,569
Total property and equipment	$	1,494,782	$	449,421

49

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Long-Term Debt

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

	June 30,
	2007		2006
First lien revolver	$	292,024	$	117,500
Second lien facility		—		75,000
High yield facility		750,000		—
Put premium financing		8,434		16,728
Capital lease obligation		561		420
Total debt		1,051,019		209,648
Less current maturities		5,508		9,584
Total long-term debt	$	1,045,511	$	200,064

Maturities of long-term debt as of June 30, 2007 are as follows (in thousands):

Year Ending June 30,
2008	$	5,508
2009		3,195
2010		240
2011		292,076
2012		—
Thereafter		750,000
Total	$	1,051,019

First Lien Revolver

Our first lien revolver was amended and restated on June 8, 2007. This facility was entered into by our subsidiary, Energy XXI Gulf Coast, Inc., and is guaranteed by us. This facility has a face value of $700 million and matures on June 8, 2011. The credit facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 1.50 percent to 2.25 percent or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.50 percent to 1.25 percent. However, if an additional equity contribution in an amount of at least $50 million is made by us to Energy XXI Gulf Coast, Inc., all of the margins above will be subject to a 0.25 percent reduction. The credit facility is secured by mortgages on at least 85 percent of the value of our proved reserves. Our initial borrowing base under the facility was $425 million, of which approximately $292.0 million was borrowed as of June 30, 2007.

Our first lien revolving credit facility requires us to maintain certain financial covenants. Specifically, we may not permit our total leverage ratio to be more than 3.5 to 1.0 (3.75 to 1.0 for the quarter ending June 30, 2007), our interest rate coverage ratio to be less than 3.0 to 1.0, or our current ratio (in each case as defined in our first lien revolving credit facility) to be less than 1.0 to 1.0, in each case, as of the end of each fiscal quarter. In addition, we are subject to various covenants including those limiting dividends and other payments, making certain investments, margin, consolidating, modifying certain agreements, transactions with affiliates, the incurrence of debt, changes in control, asset sales, liens on properties, sale leaseback transactions, entering into certain leases, the allowance of gas imbalances, take or pay or other prepayments, entering into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr., Steven A. Weyel and David West Griffin in their current executive positions, subject to certain exceptions in the event of death or disability to one of these individuals.

The first lien revolving credit facility also contains customary events of default, including, but not limited to non-payment of principal when due, non-payment of interest or fees and other amounts after a grace period,

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Long-Term Debt  – (continued)

failure of any representation or warranty to be true in all material respects when made or deemed made, defaults under other debt instruments (including the indenture governing the notes), commencement of a bankruptcy or similar proceeding by or on behalf of us or a guarantor, judgments against us or a guarantor, the institution by us to terminate a pension plan or other ERISA events, any change in control, loss of liens, failure to meet financial ratios, and violations of other covenants subject, in certain cases, to a grace period.

Second Lien Facility

To support financing of the Castex Acquisition, the Company utilized the $85.6 million in cash realized from the reduced price warrant solicitation combined with amendments of existing credit facilities by $340 million. The second lien facility, led by BNP Paribas, increased from $75 million to $300 million with a further extension to $325 million available depending upon demand during syndication. At closing of the Castex Acquisition, the Company had $300 million of the second lien facility drawn. Borrowings under the second lien facility bear interest at either: 1) a base rate of interest established by the administrative agent in New York and the federal funds rate in effect plus .5% (the “Base Rate”) plus 400 basis points; or 2) as LIBOR plus 550 basis points (the “LIBOR Rate”), at the Company’s option on conversion dates.

The syndication of the second lien facility was oversubscribed and on September 1, 2006, the second lien facility was increased to $325 million. A portion of the extension was used to reduce outstanding indebtedness under the first lien revolver. The second lien facility had a maturity of April 10, 2010. The second lien facility was repaid in full in June 2007. The pay-off payment of $328.3 million included $3.3 million in prepayment penalties. During the year ended June 30, 2007, we also wrote-off $6.0 million in deferred debt issuance costs as a result refinancing and repayment of the second lien facility.

High Yield Facility

On June 8, 2007 our subsidiary, Energy XXI Gulf Coast, Inc., completed a $750 million offering of 10 percent Senior Notes due 2013. The notes are guaranteed by us and each of Energy XXI Gulf Coast, Inc.’s existing and future material domestic subsidiaries. We have the right to redeem the notes under various circumstances and will be required to make an offer to repurchase the notes upon a change of control and from the net proceeds of asset sales under specified circumstances. A portion of the proceeds from the High Yield Facility were used to payoff our second lien facility and fund the Pogo acquisition.

Put Premium Financing

We finance puts that we purchase with our hedge providers. Substantially all of our hedges are done with members of our bank groups. Put financing is accounted for as debt and this indebtedness is pari pasu with borrowings under the first lien revolving credit facility. The hedge financing is structured to mature when the put settles so that we realize the value net of hedge financing. As of June 30, 2007 and 2006, our hedge financing totaled $8.4 million and $16.7 million, respectively.

Interest Expense

Total interest expense for the year ended June 30, 2007, of $60.3 million, consists of $7.0 million amortization and write-off of debt issuance costs, interest expense of $48.1 million associated with the first lien revolver, second lien facility and the high yield facility, $3.3 million in prepayment penalties and $1.9 million associated with put premium financing and other. Interest expense for the period ended June 30, 2006 consisted of $7.7 million related to the first and second lien facilities and $0.2 million associated with put premium financing.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Asset Retirement Obligations

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

	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
Balance at beginning of year/period	$	37,844		$	—
Liabilities acquired		37,762			36,595
Liabilities incurred		2,278			511
Liabilities settled		(17,770	)		—
Revisions in estimated cash flows		11,724			—
Accretion expense		3,991			738
Total balance at end of year/period		75,829			37,844
Less current portion		12,465			—
Long-term balance at end of year/period	$	63,364		$	37,844

Note 6 — Derivative Financial Instruments

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

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

The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the year ended June 30, 2007 resulted in an increase in crude oil and natural gas sales in the amount of $32.4 million. For the year ended June 30, 2007, we recognized a loss of approximately $0.7 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $3.3 million and an unrealized gain of approximately $0.3 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the period from inception (July 25, 2005) through June 30, 2006 resulted in an increase in oil and natural gas sales in the amount of $1.4 million. During the period from inception (July 25, 2005) through June 30, 2006,

52

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Derivative Financial Instruments  – (continued)

we recognized income of $119,736 related to the net price ineffectiveness of our hedged crude oil and natural gas contracts. Cash settlements on derivative contracts not designated as hedges resulted in a loss of $187,300 for the period from inception (July 25, 2005) through June 30, 2006.

As of June 30, 2007, we had the following contracts outstanding:

	Crude Oil							Natural Gas
Period	Volume (MBbls)		Contract Price		Fair Value Gain (Loss)			Volume (MMBtus)		Contract Price		Fair Value Gain (Loss)			Total Fair Value Gain (Loss)(2)
Puts(1)
July 1, 2007 – June 30, 2008		141	$	60.00	$	(278	)		7,380	$	8.00	$	367		$	8
July 1, 2008 – June 30, 2009		53		60.00		(47	)		2,680		8.00		(206	)		(253	)
						(325	)						161			(164	)
Swaps
July 1, 2007 – June 30, 2008		1,029	$	75.19		2,251			7,838	$	9.30		6,491			8,742
July 1, 2008 – June 30, 2009		983		69.44		(1,820	)		5,820		8.71		666			(1,154	)
July 1, 2009 – June 30, 2010		829		69.62		(1,162	)		1,960		8.52		140			(1,023	)
July 1, 2010 – June 30, 2011		340		69.64		(276	)									(276	)
						(1,007	)						7.296			6,289
Collars
July 1, 2007 – June 30, 2008		278	$	60/78		(307	)		1,010	$	8.00/11.10		546			239
July 1, 2007 – June 30, 2008		250		65/77.10		(76	)		470		8.50/10.40		293			217
July 1, 2007 – June 30, 2008									470		8.50/10.45		296			296
July 1, 2008 – June 30, 2009		106		60/78		(213	)		430		8.00/11.10		142			(71	)
July 1, 2008 – June 30, 2009									160		8.50/10.40		67			67
July 1, 2008 – June 30, 2009									160		8.50/10.45		68			68
						(597	)						1,412			815
Three – Way Collars
July 1, 2007 – June 30, 2008		417	$	45/55/61.60		(2,743	)		1,020	$	6/8/10		288			(2,455	)
July 1, 2007 – June 30, 2008		267		55/65/72.90		(534	)		420		6/8.50/9.80		81			(453	)
July 1, 2007 – June 30, 2008		72		50/65/82		(11	)									(11	)
July 1, 2008 – June 30, 2009		223		55/65/72.90		(721	)		2,000		6/8/10		(240	)		(960	)
July 1, 2008 – June 30, 2009		144		50/65/82		(101	)		720		6/8.50/9.80		36			(65	)
July 1, 2009 – June 30, 2010		144		50/65/82		(107	)		1,200		6/8/10		(24	)		(131	)
July 1, 2009 – June 30, 2010		23		55/65/72.90		(75	)		720		6/8.50/9.80		52			(23	)
July 1, 2010 – June 30, 2011		72		50/65/82		(47	)		360		6/8.50/9.80		55			8
						(4,338	)						248			(4,090	)
Net unrealized gain (loss) on derivatives					$	(6,267	)					$	9,117		$	2,850

(1) Included in natural gas puts are 6,810 MMBtus and 2,450 MMBtus of $6 to $8 put spreads for the years ended June 30, 2008 and 2009, respectively.

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

We have reviewed the financial strength of our hedge counterparties and believe the credit risk to be minimal. At June 30, 2007, we had no deposits for collateral with our counterparties.

On June 26, 2006, we entered into an interest rate costless collar to mitigate the risk of loss due to changes in interest rates. The dollar amount hedged was $75 million with the interest rate collar being 5.45 percent to 5.75 percent. At June 30, 2007, we had deferred $341,051, net of tax benefit, in losses in OCI related to this instrument.

53

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Derivative Financial Instruments  – (continued)

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

	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
Balance at beginning of year/period	$	(4,552	)	$	—
Hedging activities, net of tax:
Change in fair value of crude oil and natural gas hedging positions		7,783			(4,678	)
Change in fair value of interest rate hedging position		(467	)		126
Balance at end of year/period	$	2,764		$	(4,552	)

Note 7 — Stockholders’ Equity

Common Stock

Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders.

Preferred Stock

Our bye-laws authorize the issuance of 2,500,000 shares of preferred stock. Our Board of Directors are empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights which could adversely affect the voting power or other rights of the holders of common stock. We have not issued any preferred stock as of June 30, 2007 and 2006.

Warrants

We issued 100,000,000 warrants to stockholders in October 2005 as part of its admission to trading on the AIM. Each warrant entitles the holder to purchase one common share at a price of $5.00 per share. The warrants will be redeemable, at any time after they become exercisable, upon written consent of the placing agents, at a price of $0.01 per warrant upon 30 days notice after the warrants become exercisable, if, and only if, the last independent bid price of the common shares equals or exceeds $8.50 per share for any 20 trading days within a 30 trading day period ending three business days before we send the notice of redemption and the weekly trading volume of our common shares have exceeded 800,000 for each of the two calendar weeks before we send the notice of redemption. Investors will be afforded the opportunity to exercise the warrants on margin and simultaneously sell the shares for a “cashless exercise” if we call the warrants. The warrants will expire October 20, 2009. On June 7, 2006, we temporarily reduced the exercise price on its warrants from $5 a share to $4 per share for warrant holders who exercised prior to July 10, 2006. As of June 30, 2006, we had 81,854,871 outstanding warrants exercisable for $4 per share. At June 30, 2006, 18,145,129 warrants had been exercised, resulting in total cash inflow of approximately $65.3 million and recognition of the stock subscription receivable of approximately $7.3 million. Cash was received in the amount of approximately $7.3 million in July 2006 in satisfaction of the stock subscription receivable.

As of June 30, 2007, we had 77,389,872 outstanding warrants exercisable for $5 per share. During the year ended June 30, 2007, 3,264,999 warrants were exercised, resulting in total cash inflow of approximately $13.1 million. We also repurchased 1,200,000 warrants at a cost of $1.1 million.

54

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7 — Stockholders’ Equity  – (continued)

Unit Purchase Option

As part of the placement on the AIM, we issued to an underwriter and its designees (including its officers) an option (exercisable in whole or part) to subscribe up to 5,000,000 Units at a price of $6.60 per Unit. Each unit consists of one common share and two warrants that are each convertible into a share of our common stock at $5.00 per share. Fair value of the options, determined by using the Black-Scholes pricing model, was approximately $8.2 million, and recorded as a cost of the Placement in stockholders’ equity and additional paid-in capital. The options expire on October 20, 2010. There were no unit purchase options exercised at June 30, 2007 and 2006.

Note 8 — Supplemental Cash Flow Information

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

	Year Ended June 30, 2007		Period from Inception July 25, 2005 Through June 30, 2006
Cash paid for interest	$	48,630	$	4,760
Cash paid for income taxes		2,400		—

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

	Year Ended June 30, 2007		Period from Inception July 25, 2005 Through June 30, 2006
Put premiums acquired through financing	$	—	$	16,958
Common stock issued through recognition of a receivable		—		7,326
Additions to property and equipment by recognizing accounts payables		50,866		5,986
Additions to property and equipment by recognizing asset retirement obligations		4,618		511
Capital expenditures submitted for insurance reimbursement that were incurred by recognizing accounts payable		—		13,438
Unit purchase options issued to underwriters		—		8,157

Note 9 — Employee Benefit Plans

The Energy XXI Services, LLC 2006 Long-Term Incentive Plan (“Incentive Plan”). We adopted an incentive and retention program for our employees. Participation shares (or “Phantom Stock”) are issued from time to time at a value equal to our common share price at the time of issue. The Phantom Stock vests 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 that has vested, plus the cumulative value of dividends applicable to the Company’s stock.

At our discretion, at the time the Phantom Stock vest, we have the ability to offer the employee to accept common shares in lieu of cash. Upon a change in control of the Company, all outstanding Phantom Stock become immediately vested and payable. During the year ended June 30, 2007, the Company issued 175,500 shares to employees and directors in lieu of payment.

As of June 30, 2007 and 2006, we had 1,593,700 and 745,000 shares of Participation Shares, respectively. In addition we have outstanding 117,500 Restricted Shares as of June 30, 2007. For the year ended

55

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Employee Benefit Plans  – (continued)

June 30, 2007, we recognized compensation expense of $2,537,000. For the year ended June 30, 2006 we recognized general and administrative expense of $221,000. A liability has been recognized as of June 30, 2007 and 2006 in the amount of $1.7 million and $0.2 million, respectively, in Other current liabilities in the accompanying consolidated balance sheet. The amount of the liability will be remeasured at fair value as of each reporting date.

Defined Contribution Plans. Our employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions based upon 10 percent of annual compensation. We also sponsor a qualified 401 (k) Plan which provides for matching. The cost to us under these plans for the year ended June 30, 2007 was $1.4 million and $0.4 million, respectively. For the period from inception (July 25, 2005) to June 30, 2006 the combined cost of these plans was $0.1 million.

Note 10 — Related Party Transactions

We assumed certain contracts and obligations relating to the Placement and organization costs that were entered into and paid, prior to our formation, by The Exploitation Company, LLC (“TEC”), a partnership controlled by affiliates of ours. In addition, as a convenience to us, TEC paid for certain expenses incurred by us which were reimbursed by us on a monthly basis. TEC charged no fees or interest for this service. Furthermore, we rented office space and certain administrative services for $7,500 per month, through March 31, 2006, the date the arrangement ended with TEC. We paid TEC $37,500 of rental expense during the period ended June 30, 2006.

We entered into employment agreements with each of Messrs. Schiller, Weyel, and Griffin, who serve as our Chief Executive Officer and Chairman of our Board of Directors, President and Chief Operating Officer, and Chief Financial Officer, respectively. Under these agreements, each of the executives will also be entitled to additional benefits, including reimbursement of business and entertainment expenses, paid vacation, company-provided use of a car (or a car allowance), life insurance, certain health and country club memberships, and participation in other company benefits, plans, or programs that may be available to other executive employees of ours from time to time. Each employment agreement has an initial term beginning on April 4, 2006, and ending on October 20, 2008, after which it will be automatically extended for successive one-year terms unless either the executive or we give written notice within 90 days prior to the end of the term that such party desires not to renew the employment agreement.

Note 11 — Earnings Per Share

Basic earnings per share of common stock is computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of restricted stock and the potential dilution that would occur if warrants and unit purchase options 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):

	Year Ended June, 30, 2007		Period from Inception July 25, 2005 Through June 30, 2006
Net Income	$	24,130	$	6,942
Weighted average shares outstanding for basic EPS		83,959		49,839
Add dilutive securities: warrants and unit purchase options		—		8,636
Weighted average shares outstanding for diluted EPS		83,959		58,475
Earnings per share
Basic	$	0.29	$	0.14
Diluted		0.29		0.12

56

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Hurricanes Katrina and Rita

We acquired properties that were damaged by hurricanes Katrina and Rita. Our insurance coverage is an indemnity program that provides for reimbursement after funds are expended.

In January 2007, we reached a global settlement for $38.8 million with our insurance carrier. The entire amount has been received.

Note 13 — Commitments and Contingencies

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

Lease Commitments. We have a non-cancelable operating lease for office space that expires on December 31, 2017. Future minimum lease commitments as of June 30, 2007 under the operating leases are as follows (in thousands):

Year Ending June 30,
2008	$	1,294
2009		1,294
2010		1,294
2011		1,294
2012		1,294
Thereafter		7,099
Total	$	13,569

Rent expense for the year/period ended June 30, 2007 and 2006 was approximately $735,000 and $76,000, respectively.

Letters of Credit and Performance Bonds. The Company had $5.5 million in letters of credit and $43.2 million of performance bonds outstanding as of June 30, 2007.

Drilling Rig Commitments. The Company has entered into three drilling rig commitments ranging from 31 to 87 days, the latest commencing on June 30, 2007. Total commitments under these contracts to secure drilling rigs as of June 30, 2007 are approximately $8.9 million.

Note 14 — Income Taxes

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

The amounts of income before income taxes attributable to U.S. and Non-U.S. operations are as follows:

	Year Ended June 30, 2007		Period from Inception July 25, 2005 Through June 30, 2006
	(In Thousands)
U.S.	$	14,215	$	3,017
Non U.S.		22,580		5,652
Income before income taxes	$	36,795	$	8,669

57

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14 — Income Taxes  – (continued)

The components of our income tax provision (benefit) are as follows:

	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
	(In Thousands)
Current:
U.S.	$	(837	)	$	836
State		(28	)		77
Total current		(865	)		913
Deferred:
U.S.	$	11,993		$	814
State	$	1,537		$	—
Total deferred	$	13,530		$	814
Total income tax provision	$	12,665		$	1,727

The following is a reconciliation of statutory income tax expense to our income tax provision:

	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
	(In Thousands)
Income before income taxes:	$	36,795		$	8,669
Statutory rate		35	%		35	%
Income tax expense computed at statutory rate	$	12,878		$	3,034
Reconciling items:
Federal withholding obligation		7,477			—
Non taxable foreign income		(7,903	)		(1,357	)
State income taxes, net of federal tax benefit		980			50
Other-net		(767	)		—
Tax provision	$	12,665		$	1,727

58

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14 — Income Taxes  – (continued)

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below:

	June 30,
	2007			2006
	(In Thousands)
Deferred tax assets
Derivative instruments	$	—		$	2,451
Tax loss carryforwards on U.S. operations		89,278			—
Accrued interest expense		9,604			—
Asset retirement obligation		26,540			258
Employee benefit plans		641			104
Other		451			68
Total deferred tax assets		126,514			2,881
Deferred tax liabilities
Derivative instruments and other		1,495			143
Oil and natural gas properties		117,656			—
Federal withholding obligation		8,238			—
Other property and equipment		10,697			1,101
Deferred state tax obligation		4,260			—
Total deferred tax liabilities		142,346			1,244
Net deferred tax asset (liability)	$	(15,832	)	$	1,637
Reflected in the accompanying balance sheet as:
Non-current deferred tax asset	$	—		$	1,780
Current deferred tax liability		(1,044	)		(143	)
Non-current deferred tax liability		(14,788	)		—
Net deferred tax asset (liability)	$	(15,832	)	$	1,637

At June 30, 2007, we have a federal tax loss carryforward of approximately $245.8 million and a state income tax loss carryforward of approximately $62 million, which will expire in various amounts beginning in 2022 and ending in 2027.

59

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 — Concentations of Credit Risk

Major Customers. We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices. The following table identifies customers from whom we derived 10 percent or more our net oil and natural gas revenues during the year ended June 30, 2007 and during the period from inception (July 25, 2005) through June 30, 2006. Based on the availability of other customers, we do not believe the loss of any of these customers would have a significant effect on our operations or financial condition.

	Percent of Total Revenue
Customer	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
Shell Trading Company		35	%		—
Chevron, USA		—			57	%
Louis Dreyfus Energy Services, LP		—			14	%

Accounts Receivable. Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Based on the current demand for oil and natural gas, we do not expect that termination of sales to any of our current purchasers would have a material adverse effect on our ability to find replacement purchasers and to sell our production at favorable market prices.

Derivative Instruments. Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We believe that our credit risk related to the futures and swap contracts is no greater than the risk associated with the primary contracts and that the elimination of price risk through our hedging activities reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk.

Cash and Cash Equivalents. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. At times cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation.

Note 16 — Fair Value of Financial Instruments

We include fair value information in the notes to the consolidated financial statements when the fair value of our financial instruments is different from the book value. We believe that the carrying value of our cash and cash equivalents, receivables, accounts payable, accrued liabilities and short-term and long-term debt, materially approximates fair value due to the short-term nature and the terms of these instruments.

60

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Prepayments and Accured Liabilities

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

	June 30,
	2007		2006
Prepaid expenses and other current assets
Advances to joint interest partners	$	18,841	$	333
Insurance		—		7,695
Estimated federal tax payments		2,000		—
Other		1,029		1,172
Total prepaid expenses and other current assets	$	21,870	$	9,200
Accrued liabilities
Asset retirement obligations-current	$	12,465	$	—
Employee benefits and payroll		7,540		94
Interest		5,795		2,533
Due to Pogo for non-exercise of preferential rights		3,000		—
Undistributed oil and gas proceeds		—		5,617
Other		4,611		3,219
Total accrued liabilities	$	33,411	$	11,463

Note 18 — Subsequent Event

In July 2007, we acquired a 49.5% limited partnership interest in the Castex Energy 2007, L.P. (the “Partnership”). The Partnership was formed on May 30, 2007 with Castex Energy, Inc. as general partner and Castex Energy 2005, L.P. as the limited partner. Revenue and expenses are allocated 1% to the general partner and 99% to the limited partners. The Partnership was formed to acquire certain onshore southern Louisiana assets from EPL of Louisiana, L.L.C. effective April 1, 2007 for consideration of $71.7 million.

The Partnership financed the acquisition with a $73 million credit agreement with Lehman Brothers Inc. acting as sole arranger and Lehman Commercial Paper Inc. as administrative agent. The credit agreement required the Partnership to enter into certain derivative transactions and under certain circumstances requires additional capital contributions by the partners of up to $15 million.

61

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 19 — Selected Quarterly Financial Data – Unaudited

Unaudited quarterly financial data are as follows (in thousands, except per share amounts):

Year Ended June 30, 2007	Fourth Quarter		Third Quarter		Second Quarter		First Quarter
Revenues	$	118,716	$	77,608	$	79,143	$	65,817
Operating income		23,263		25,908		28,647		17,397
Net income	$	2,208	$	9,581	$	10,408	$	1,933
Basic earnings per common share(1)	$	0.03	$	0.11	$	0.12	$	0.02
Diluted earnings per common share(1)		0.02		0.11		0.12		0.02

Period Ended June 30, 2006	Fourth Quarter		Third Quarter			Second Quarter			First Quarter
Revenues	$	47,112	$	—		$	—		$	—
Operating income (loss)		13,319		(1,225	)		(414	)		(78	)
Net income (loss)	$	5,534	$	67		$	1,497		$	(156	)
Basic earnings per common share	$	0.11	$	0.00		$	0.03		$	0.00
Diluted earnings per common share		0.09		0.00			0.03			0.00

(1) The sum of the individual quarterly earnings per share many not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

Note 20 — Supplementary Financial Information – Unaudited

The supplementary data presented herein reflects information for all of our oil and gas producing activities. Costs incurred for oil and gas property acquisition, exploration and development activities follow:

	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
	(In Thousands)
Oil and Gas Activities
Property acquisition
Proved	$	632,707		$	393,087
Unproved		134,340			50,840
Exploration costs		67,140			—
Development costs		362,219			18,002
Costs incurred for oil and gas activities		1,196,406			461,929
Other property and equipment		2,468			1,701
Total costs incurred		1,198,874			463,630
Less acquisitions		(717,618	)		(448,374	)
Less asset retirement obligations and other-net		(49,429	)		4,447
Capital expenditures	$	431,827		$	19,703

62

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 20 — Supplementary Financial Information – Unaudited  – (continued)

We excluded the following costs related to unproved property costs and major development projects (in thousands):

	June 30
	2007		2006
Unproved properties	$	243,981	$	50,840
Wells in progress		7,185		—
	$	251,166	$	50,840

The costs related to unproved properties will be included in the amortization base when a determination is made related to the existence of proved reserves. The wells in progress will be transferred into the amortization base during fiscal 2008 when the results of the drilling activities are known.

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our and gas properties located entirely within the United States of America, are based on evaluations prepared by our engineers and third-party reservoir engineers. Reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost changes except by contractual arrangements. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise that those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

Estimated quantities of proved domestic oil and gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and thousands of cubic feet (“MMcf”) for each of the periods indicated were as follows:

	Oil (MBbls)			Natural Gas (MMcf)			Total (MBOE)
Proved reserves at inception (July 25, 2005)		—			—			—
Production		(446	)		(2,459	)		(856	)
Revisions of previous estimates		106			436			179
Purchases of minerals in place		14,160			66,674			25,272
Proved reserves at June 30, 2006		13,820			64,651			24,595
Production		(2,852	)		(18,369	)		(5,914	)
Extensions and discoveries		4,726			37,235			10,932
Revisions of previous estimates		(523	)		(16,233	)		(3,229	)
Sales of reserves		(224	)		(991	)		(389	)
Purchases of minerals in place		15,393			85,539			29,650
Proved reserves at June 30, 2007		30,340			151,832			55,645
Proved developed reserves
June 30, 2006		8,922			42,246			15,963
June 30, 2007		20,978			96,751			37,103

Standardized Measure of Discounted Future Net Cash Flows

A summary of the standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves is shown below. Future net cash flows are computed using year end commodity prices, costs and statutory tax rates (adjusted for tax credits and other items) that relate to our existing proved crude oil and natural gas reserves.

63

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 20 — Supplementary Financial Information – Unaudited  – (continued)

The standardized measure of discounted future net cash flows related to proved oil and gas reserves as of June 30, 2007 and 2006 are as follows (in thousands):

	June 30,
	2007		2006
Future cash inflows	$	3,197,234	$	1,356,910
Less related future
Production costs		531,253		321,502
Development costs		582,664		231,692
Income taxes		253,350		144,669
Future net cash flows		1,829,967		659,047
10% annual discount for estimated timing of cash flows		436,813		184,549
Standardized measure of discounted future net cash flows	$	1,393,154	$	474,498

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil and natural gas reserves follows (in thousands):

	Year Ended June 30, 2007			Period from Inception July 25, 2005 Through June 30, 2006
Beginning of year/period	$	474,498		$	—
Revisions of previous estimates
Changes in prices and costs		119,317			(22,732	)
Changes in quantities		(58,122	)		19,294
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		298,677			—
Purchases of reserves in place		859,709			620,040
Sales of reserves in place		(5,085	)		—
Accretion of discount		57,868			—
Sales, net of production costs		(268,704	)		(37,126	)
Net change in income taxes		(88,656	)		(103,941	)
Changes in rate of production and other		3,652			(1,037	)
Net change		918,656			474,498
End of year/period	$	1,393,154		$	474,498

64

Item 9. Changes In and Disagreements With Accountants On Accounting and Financial Disclosure

None

Item 9A. Controls and Procedures

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

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

There was no change in our internal control over financial reporting during our last quarterly period ended June 30, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None

65

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K and to the information set forth in Item 4 of this report.

Item 11. Executive Compensation

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

Item 12. Security Ownership Of Certain Beneficial Owners and Management Related Shareholder Matters

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

Item 13. Certain Relationships and Related Transactions and Director Independence

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

Item 14. Principal Accountant Fees and Services

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

66

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Financial Statements, Financial Statement Schedules and Exhibits

1. Consolidated Financial Statements. See “Item 8 Financial Statements and Supplementary Data — Index to Financial Statements.”

2. Consolidated Financial Statement Schedules. All Schedules for which provision is made in Regulation S-X either are not required under the related instruction or are inapplicable and, therefore, have been omitted.

3. Exhibits. See the Exhibit Index for a list of those exhibits filed herewith, which index also includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 (b)(10)(iii) of regulation S-K.

(b) Exhibit index.

67

Exhibit Number	Description of Exhibit
3.1*	Certificate of Incorporation of Energy XXI (Bermuda) Limited
3.2*	Certificate of Incorporation on Change of Name of Energy XXI (Bermuda) Limited
3.3*	Certificate of Deposit of Memorandum of Increase of Share Capital of Energy XXI (Bermuda) Limited
3.4*	Altered Memorandum of Association of Energy XXI (Bermuda) Limited
3.5*	Bye-Laws of Energy XXI (Bermuda) Limited
4.1*	Investor Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) Limited, Sunrise Securities Corp. and Collins Steward Limited
4.2*	Registration Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) and the investors named therein.
4.3*	Indenture, by and among, among Energy XXI Gulf Coast, Inc., Energy XXI (Bermuda) Limited, the Guarantors and Wells Fargo Bank, a national banking association, as trustee, dated as of June 8, 2007.
10.1*	Amended and Restated First Lien Credit Agreement, dated June 8, 2007, among the Issuer, the guarantors named therein, the various financial institutions, as lenders, The Royal Bank of Scotland plc, as Administrative Agent, RBS Securities Corporation and BNP Paribas, as Syndication Agent, and Guaranty Bank, FSB and BMO Capital Markets Financing, Inc., as Co-Documentation Agents
10.2*†	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and John D. Schiller, Jr.
10.3*†	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and Steve Weyel
10.4*†	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and David West Griffin
10.5*†	2006 Long-Term Incentive Plan of Energy XXI Services, LLC
10.6*†	Form of Restricted Stock Grant Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC
10.7*†	Form of Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC
10.8*†	Appointment letter dated August 31, 2005 for William Colvin
10.9*†	Appointment letter dated August 31, 2005 for David Dunwoody
10.10*†	Appointment letter dated April 16, 2007 for Hill Feinberg
10.11*†	Appointment letter dated April 24, 2007 for Paul Davison
10.12*	Letter Agreement dated September 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.
10.13*	Assumption and Indemnity Agreement dated September 15, 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.
10.14*	Purchase and Sale Agreement dated as of June 6, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.

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Exhibit Number	Description of Exhibit
10.15*	First Amendment to Purchase and Sale Agreement dated as of July 5, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.16*	Second Amendment to Purchase and Sale Agreement dated as of July 10, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.17*	Third Amendment to Purchase and Sale Agreement dated as of July 27, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.18*	Purchase and Sale Agreement dated as of February 21, 2006 by and between Marlin Energy, L.L.C., as Seller, and Energy XXI Gulf Coast, Inc., as Buyer.
10.19*	Joinder and Amendment to Purchase and Sale Agreement dated as of March 2, 2006 by and among Marlin Energy, L.L.C., Energy XXI Gulf Coast, Inc. and Energy XXI (US Holdings) Limited.
10.20*	Second Amendment to Purchase and Sale Agreement dated as of March 12, 2006 by and among Marlin Energy, L.L.C., Energy XXI Gulf Coast, Inc. and Energy XXI (US Holdings) Limited.
10.21*	Participation Agreement dated as January 26, 2007 by and between Centurion Exploration Company and Energy XXI Gulf Coast, Inc.
10.22*	Purchase and Sale Agreement, dated as of April 24, 2007, by and between Pogo Producing Company and Energy XXI GOM, LLC
10.23*	Registration Rights Agreement dated as of June 8, 2007 among Energy XXI Gulf Coast, Inc., the Guarantors named therein, the Initial Purchasers named therein, and the Purchasers named therein.
12.1	Ratio of Earnings to Fixed Charges - Energy XXI Gulf Coast, Inc.
21.1*	Subsidiary List
23.1	Consent of UHY LLP
23.2	Consent of Netherland, Sewell & Associates, Inc.
23.3	Consent of Miller and Lents, Ltd.
23.4	Consent of Ryder Scott Company, L.P.
31.1	Rule 13a-14(a)/15d-14(a) Certification of the Chairman and Chief Executive Officer of Energy XXI (Bermuda) Limited
31.2	Rule 13a-14(a)/15d-14(a) Certification of the Chief Financial Officer of Energy XXI (Bermuda) Limited
32.1	Section 1350 Certification
32.2	Section 1350 Certification

* Exhibit incorporated herein by reference as indicated were filed as exhibits to the Energy XXI Gulf Coast, Inc. Registration Statement on Form S-4 filed on August 22, 2007.

† Exhibit constitutes a management contract or compensatory plan or arrangement.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

Below are definitions of key certain technical industry terms used in this Form 10-K.

Bbls	Barrels	MMBbls	Millions of Barrels
MCF	Thousand Cubic Feet	MMCF	Million Cubic Feet
BCF	Billion Cubic Feet	MMBTU	Million British Thermal Units
DD&A	Depreciation, Depletion and Amortization	BOE	Barrel of Oil Equivalent
MBbls	Thousands of Barrels	MBOE	Thousand Barrels of Oil Equivalent

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

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

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

Developed acreage is acreage that is allocated or assignable to producing wells or wells capable of production.

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

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

Exploitation is drilling wells in areas proven to be productive.

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

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

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

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

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

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.

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

Natural gas is converted into one barrel of oil equivalent based on 6 MCF of gas to one barrel of oil.

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

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

Production costs are costs incurred to operate and maintain our wells and related equipment and facilities. These costs include lease operating or well operating expenses and severance taxes.

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

Proved developed reserves are the portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. For complete definitions of proved developed natural gas, NGLs and crude oil reserves, refer to the Securities and Exchange Commission’s Regulation S-X, Rule 4-10(a)(2), (3) and (4).

Proved reserves represent estimated quantities of natural gas, NGLs and crude oil which geological and engineering data demonstrate, with reasonable certainty, can be recovered in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if shown to be economically producible by either actual production or conclusive formation tests. For complete definitions of proved natural gas, NGLs and crude oil reserves, refer to the Securities and Exchange Commission’s Regulation S-X, Rule 4-10(a)(2), (3) and (4).

Proved undeveloped reserves are the portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for completion. For complete definitions of proved undeveloped natural gas, NGLs and crude oil reserves, refer to the Securities and Exchange Commission’s Regulation S-X, Rule 4-10(a)(2), (3) and (4).

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

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

Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas.

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.

Zone is a stratigraphic interval containing one or more reservoirs.

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SIGNATURES REQUIRED FOR FORM 10-K

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, 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/ John D. Schiller, Jr.
John D. Schiller, Jr.
Chairman of the Board and
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Energy XXI (Bermuda) Limited and in the capacities and on the dates indicated.

/s/ John D. Schiller, Jr. John D. Schiller, Jr.	Chairman of the Board and Chief Executive Officer	September 27, 2007
/s/ Steven A. Weyel Steven A. Weyel	President, Chief Operating Officer and Director	September 27, 2007
/s/ David West Griffin David West Griffin	Chief Financial Officer and Director	September 27, 2007
/s/ William Colvin William Colvin	Director	September 27, 2007
/s/ Paul Davison Paul Davison	Director	September 27, 2007
/s/ David M. Dunwoody David M. Dunwoody	Director	September 27, 2007
/s/ Hill A. Feinberg Hill A. Feinberg	Director	September 27, 2007

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EXHIBIT INDEX

Exhibit Number	Description of Exhibit
3.1*	Certificate of Incorporation of Energy XXI (Bermuda) Limited
3.2*	Certificate of Incorporation on Change of Name of Energy XXI (Bermuda) Limited
3.3*	Certificate of Deposit of Memorandum of Increase of Share Capital of Energy XXI (Bermuda) Limited
3.4*	Altered Memorandum of Association of Energy XXI (Bermuda) Limited
3.5*	Bye-Laws of Energy XXI (Bermuda) Limited
4.1*	Investor Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) Limited, Sunrise Securities Corp. and Collins Steward Limited
4.2*	Registration Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) and the investors named therein.
4.3*	Indenture, by and among, among Energy XXI Gulf Coast, Inc., Energy XXI (Bermuda) Limited, the Guarantors and Wells Fargo Bank, a national banking association, as trustee, dated as of June 8, 2007.
10.1*	Amended and Restated First Lien Credit Agreement, dated June 8, 2007, among the Issuer, the guarantors named therein, the various financial institutions, as lenders, The Royal Bank of Scotland plc, as Administrative Agent, RBS Securities Corporation and BNP Paribas, as Syndication Agent, and Guaranty Bank, FSB and BMO Capital Markets Financing, Inc., as Co-Documentation Agents
10.2*†	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and John D. Schiller, Jr.
10.3*†	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and Steve Weyel
10.4*†	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and David West Griffin
10.5*†	2006 Long-Term Incentive Plan of Energy XXI Services, LLC
10.6*†	Form of Restricted Stock Grant Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC
10.7*†	Form of Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC
10.8*†	Appointment letter dated August 31, 2005 for William Colvin
10.9*†	Appointment letter dated August 31, 2005 for David Dunwoody
10.10*†	Appointment letter dated April 16, 2007 for Hill Feinberg
10.11*†	Appointment letter dated April 24, 2007 for Paul Davison
10.12*	Letter Agreement dated September 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.
10.13*	Assumption and Indemnity Agreement dated September 15, 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.
10.14*	Purchase and Sale Agreement dated as of June 6, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.

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Exhibit Number	Description of Exhibit
10.15*	First Amendment to Purchase and Sale Agreement dated as of July 5, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.16*	Second Amendment to Purchase and Sale Agreement dated as of July 10, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.17*	Third Amendment to Purchase and Sale Agreement dated as of July 27, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.18*	Purchase and Sale Agreement dated as of February 21, 2006 by and between Marlin Energy, L.L.C., as Seller, and Energy XXI Gulf Coast, Inc., as Buyer.
10.19*	Joinder and Amendment to Purchase and Sale Agreement dated as of March 2, 2006 by and among Marlin Energy, L.L.C., Energy XXI Gulf Coast, Inc. and Energy XXI (US Holdings) Limited.
10.20*	Second Amendment to Purchase and Sale Agreement dated as of March 12, 2006 by and among Marlin Energy, L.L.C., Energy XXI Gulf Coast, Inc. and Energy XXI (US Holdings) Limited.
10.21*	Participation Agreement dated as January 26, 2007 by and between Centurion Exploration Company and Energy XXI Gulf Coast, Inc.
10.22*	Purchase and Sale Agreement, dated as of April 24, 2007, by and between Pogo Producing Company and Energy XXI GOM, LLC
10.23*	Registration Rights Agreement dated as of June 8, 2007 among Energy XXI Gulf Coast, Inc., the Guarantors named therein, the Initial Purchasers named therein, and the Purchasers named therein.
12.1	Ratio of Earnings to Fixed Charges - Energy XXI Gulf Coast, Inc.
21.1*	Subsidiary List
23.1	Consent of UHY LLP
23.2	Consent of Netherland, Sewell & Associates, Inc.
23.3	Consent of Miller and Lents, Ltd.
23.4	Consent of Ryder Scott Company, L.P.
31.1	Rule 13a-14(a)/15d-14(a) Certification of the Chairman and Chief Executive Officer of Energy XXI (Bermuda) Limited
31.2	Rule 13a-14(a)/15d-14(a) Certification of the Chief Financial Officer of Energy XXI (Bermuda) Limited
32.1	Section 1350 Certification
32.2	Section 1350 Certification

* Exhibit incorporated herein by reference as indicated were filed as exhibits to the Energy XXI Gulf Coast, Inc. Registration Statement on Form S-4 filed on August 22, 2007.

† Exhibit constitutes a management contract or compensatory plan or arrangement.

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