As filed with the Securities and Exchange Commission on June 26, 2007

Registration No. 333-

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

ENERGY XXI (BERMUDA) LIMITED

(Exact name of registrant as specified in its charter)

Bermuda	1311	98-0499286
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

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

Hamilton HM EX, Bermuda

(441) 295-2244

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

Juliet Evans

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

Hamilton HM EX, Bermuda

(441) 298-3262

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:

Vinson & Elkins L.L.P.

2300 First City Tower, 1001 Fannin

Houston, Texas 77002

(713) 758-2222

Attn: T. Mark Kelly

Approximate date of commencement of proposed sale to the public:    From time to time after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, please check the following box.    x

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered		Proposed Maximum Aggregate Offering Price			Proposed Maximum Aggregate Offering Price		Amount of Registration Fee
Common Stock, par value $0.001		60,449,358	$	6.04(1	)	$	365,114,123	$	11,209
Common Stock, par value $0.001, issuable upon exercise of warrants exercisable at $5.00 per share		73,053,966	$	5.00(2	)	$	365,269,830	$	11,214
Common Stock, par value $0.001, issuable upon exercise of unit purchase options exercisable at $6.60 per unit purchase option(3)		5,000,000	$	6.60(4	)	$	33,000,000	$	1,014
Common Stock, par value $0.001, issuable upon exercise of warrants at $5.00 per share issuable upon exercise of unit purchase options exercisable at $6.60 per unit purchase option(3)		10,000,000	$	5.00(2	)	$	50,000,000	$	1,535
Total:		148,503,324		N/A		$	813,383,953	$	24,972	(5)

(1) Estimated solely for purposes of calculating the registration fee in accordance with Rule 457(c) under the Securities Act of 1933, as amended (“the Securities Act”), using the average of the high and low price as reported on the Alternative Investment Market of the London Stock Exchange on June 22, 2007.

(2) Pursuant to Rule 457(g) under the Securities Act, the maximum offering price per security represents the exercise price of the warrants.

(3) Each unit purchase option gives the holder the option of acquiring for $6.60 per unit one common share and two warrants to purchase common share at $5.00 per share.

(4) Pursuant to Rule 457(g) under the Securities Act, the maximum offering price per security represents the exercise price of the unit purchase option.

(5) A registration fee of $17,696 has previously been paid with respect to 115,302,362 shares of common stock for Registration Statement File No. 333-140916, such shares are being carried over to this Registration Statement pursuant to rule 457(p) under the Securities Act. Accordingly, the amount of registration fee with respect to this Registration Statement is reduced to $7,256.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

EXPLANATORY NOTE

Energy XXI (Bermuda) Limited (the "Company") has previously filed a Registration Statement on Form S-1 and certain amendments thereto, File No. 333-140916 (the "Prior Registration Statement"), to register 115,302,363 shares of its common stock, consisting of up to 40,763,202 shares of common stock, 59,539,161 shares of common stock issuable upon exercise of common stock purchase warrants, 5,000,000 shares of common stock issuable upon exercise of unit purchase options and 10,000,000 shares of common stock issuable upon exercise of common sock purchase warrants issuable upon exercise of unit purchase options. The Prior Registration Statement was declared effective by the SEC on April 6, 2007. Pursuant to Rule 429 under the Securities Act, this Registration Statement, upon effectiveness, constitutes a post-effective amendment to the Prior Registration Statement terminating the offering of the 115,302,363 shares of common stock covered by the Prior Registration Statement. Pursuant to Rule 457(p) under the Securities Act, this Registration Statement carries forward from the Prior Registration Statement 115,302,363 shares of common stock, and accordingly the filing fee associated with this Registration Statement is offset by the total dollar amount of the filing fee associated with the Prior Registration Statement. This Registration Statement also registers an additional 33,100,961 shares of common stock, consisting of 19,686,156 shares of common stock, which the Company has voluntarily agreed to register, and 13,414,805 shares of common stock isssuable upon exercise of common stock purchase warrants, which the Company has agreed to register pursuant to the terms of an Investor Rights Agreement, dated October 13, 2005.

The information in this prospectus is not complete and may be changed. Neither we nor the selling shareholders may sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED JUNE 25, 2007

PRELIMINARY PROSPECTUS

148,503,324 Shares

ENERGY XXI (BERMUDA) LIMITED

Common Stock

This prospectus relates to the resale by the selling stockholders of up to 148,503,324 shares of our common stock, consisting of up to 60,449,966 shares of common stock, 73,053,966 shares of common stock issuable upon exercise of common stock purchase warrants, 5,000,000 shares of common stock issuable upon exercise of unit purchase options and 10,000,000 shares of common stock issuable upon exercise of common stock purchase warrants issuable upon exercise of unit purchase options. We are not selling any shares of common stock under this prospectus and will not receive any proceeds from the sale of common stock by the selling stockholders.

As part of our initial public offering on the “Alternative Investment Market” of the London Stock Exchange in October 2005, we issued common shares, common stock purchase warrants (each exercisable into one common share for $5.00) and unit purchase options (each exercisable for $6.60 into one common share and two common stock purchase warrants (each common stock purchase warrant then exercisable for one common share for $5.00)). Pursuant to an Investor Rights Agreement dated October 13, 2005 by and among us, Sunrise Securities Corp. and Collins Stewart Limited, we agreed to register the common stock underlying the warrants and the unit purchase options. We have also offered to register for sale the common shares of any holder of common shares electing to participate in this offering.

The shares of common stock to which this prospectus relates may be offered and sold from time to time directly by the selling stockholders or alternatively through underwriters or broker-dealers or agents. The shares of common stock may be sold in one or more transactions, at fixed prices, at prevailing market prices at the time of sale, or at negotiated prices.

Our restricted and unrestricted common stock trades on the Alternative Investment Market of the London Stock Exchange under the symbols “EXXS” and “EXXI”, respectively, and on the United States Over-the-Counter Bulletin Board under the symbol “EXXIF.OB”.

Investing in our common stock involves a high degree of risk. See “Risk Factors” beginning on page 5.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus is accurate or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is                     , 2007

TABLE OF CONTENTS

	Page
Summary		1
Risk Factors		5
Cautionary Statement Concerning Forward-Looking Statements		14
Use of Proceeds		14
Selected Financial Information		15
Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Business		31
Properties		39
Security Ownership of Certain Beneficial Owners and Management		42
Directors and Executive Officers		44
Executive Compensation		47
Certain Relationships and Related Transactions		50
Legal Proceedings		50
Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters		51
Description of Registrant’s Securities to be Registered		51
Plan of Distribution		52
Selling Stockholders		54
Legal Matters		62
Experts		62
Where You Can Find More Information		62
Index to Financial Statements		F-1

SUMMARY

This summary contains basic information about us and the offering. Because it is a summary, it does not contain all the information that you should consider before investing in our common stock. You should read and carefully consider this entire prospectus before making an investment decision, especially the information presented under the heading “Risk Factors” and the consolidated and pro forma financial statements and the accompanying notes thereto included elsewhere in this prospectus.

Overview

Energy XXI (Bermuda) Limited is an independent energy company engaged in the acquisition, development, exploration and production of oil and natural gas reserves in the United States Gulf Coast and the Gulf of Mexico. 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. Since our incorporation, 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 (the “Pogo Properties”) from Pogo Producing Company (the “Pogo Acquisition”). Our first and second major acquisitions closed on April 4, 2006 and July 28, 2006. In October 2005, we completed a $300 million initial public offering of common stock and warrants on the “Alternative Investment Market” of the London Stock Exchange.

We operate geographically focused producing reserves and target the acquisition of oil and gas properties that lend themselves to an intensive exploitation program to significantly increase production and ultimate recovery of reserves, or that alternatively offer the potential for using reprocessed seismic data to identify previously overlooked exploration opportunities. Approximately two-thirds of our capital is currently spent on exploitation with the balance of our capital expenditures split between lower risk exploration opportunities and higher impact exploration plays. Since acquiring our largest field in April 2006, the South Timbalier 21 field, and employing our focused exploitation program, we have realized a 90% increase in daily production levels from inception to the month ended March 31, 2007. Production from this large legacy field is currently at a 21-year high. Our exploitation of this field has involved the drilling of 13 new wells and 10 workovers of existing wells through March 31, 2007. We have 19 remaining identified proven well opportunities in South Timbalier 21 and anticipate selectively employing our exploitation strategy to our other offshore assets.

Our high quality assets are located in mature and predictable fields. As of March 31, 2007, after giving effect to the Pogo Acquisition, we operate or have an interest in 284 producing wells over 283,000 net acres in 73 fields. All of our properties are located on the Gulf Coast and in the Gulf of Mexico, with approximately 60% of our proved reserves being offshore. All of the Pogo Properties are located offshore. This concentration facilitates our ability to manage the operated fields efficiently, and our high number of wellbore locations provides significant diversification of our reserves. We believe managing our assets is a key strength, and we operate 79% of our properties. We utilize an exploitation strategy with respect to our offshore Gulf of Mexico assets to enhance production, from our existing reserve base, as evidenced by our success with the South Timbalier 21 field. In the Gulf Coast, our strategy is to acquire, merge and reprocess seismic data to identify previously overlooked exploration opportunities. We have a significant seismic database covering approximately 2,400 square miles from our existing operations. Through the exploration of our existing asset base, we have identified at least 109 development and exploration opportunities. We believe the Pogo Properties will lend themselves well to our aggressive exploitation strategy to increase production from mature legacy fields and will provide us extensive incremental exploration opportunities within our core geographic area.

We actively manage price risk and hedge a high percentage of our proved developing producing reserves to enhance revenue certainty and predictability. We intend to apply the same strategy with regard to the Pogo Properties. Our disciplined hedging 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 hedging 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”), and their Gulf of Mexico assets consisting of working interests in 30 oil and gas fields with 118 producing wells. In July 2006, we acquired additional oil and gas working interests in 15 onshore and inland water Louisiana Gulf Coast fields from affiliates of Castex Energy, Inc. (“Castex”). There are 49 producing wells in these fields we acquired from Castex. Pro forma for the acquisition of the Castex assets, our net proved reserve base totaled over 37.5 MMBoe as of June 30, 2006. Our average daily production for the three months ended March 31, 2007 was approximately 14,500 Boed. On June 8, 2007, we completed the Pogo Acquisition. The net proved reserve base of the Pogo Properties totaled 20.9 MMBoe as of December 31, 2006. We expect the Pogo Properties to add 7,400 Boed to our current production profile, not including the additional 1,500 Boed of production shut-in due to hurricane related damage, following an integration period and based on current operating assumptions.

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We intend to grow our reserve base and increase production through strategic acquisitions of oil and natural gas properties, our drilling program and the further optimization of production.

Proved Reserves and Production Summary

The reserve reports associated with the properties we acquired in the Marlin and Castex acquisitions were prepared as of June 30, 2006 and the reserve report associated with the Pogo Properties was prepared as of December 31, 2006. Because these reserve reports were prepared on different dates, the proved reserves set forth therein are not comparable to each other as they are calculated utilizing differing assumptions specific to the respective dates of these reports, including commodity prices. As such, we believe it is not meaningful to present, and therefore we have not presented, the combined or pro forma information of our properties and the Pogo Properties derived from these reserve reports.

	Energy XXI			Pogo Properties
Proved Reserve Summary:
Proved reserves		37.5 MMBoe(1)			20.9 MMBoe(2)
Percentage oil and natural gas liquids		40	%		70	%
Percentage offshore		60	%		100	%

			Combined Energy XXI and Pogo Properties
Production Summary:
Average daily production(3)	14,500	6,400	20,900
Producing wells	167	117	284

(1) Based on June 30, 2006 reserve reports completed by Netherland, Sewell and Associates, Inc. and Miller and Lents, Ltd. for the Marlin and Castex acquisitions, respectively.

(2) Based on a December 31, 2006 reserve report completed by Ryder Scott Company, L.P.

(3) Average Boed for the quarter ended March 31, 2007. Average daily production for the Pogo Properties is based on March 31, 2007 lease operating statements provided to us by Pogo.

Drilling Activities

The following table shows our drilling and completion activity for the nine month period ended March 31, 2007 and for the period from July 25, 2005 (inception) to June 30, 2006. Prior to our first acquisition on April 4, 2006, we had no reserves or development or exploratory activity. Except as noted below, the table reflects only the activity during our period of ownership of the properties. In the table, “gross” refers to the total number of wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest in such wells.

	Nine Months Period Ended March 31, 2007								Period from July 25, 2005 to June 30, 2006(1)
	Gas		Oil		Dry		Total		Gas		Oil		Dry		Total
Development
Gross		8		4		4		16		3		5		2		10
Net		5.7		4		4		13.7		1.8		5		1.5		8.3
Exploratory
Gross		5		3		4		12		—		—		—		—
Net		2.8		2.1		.8		5.7		—		—		—		—

(1)Includes drilling activity for the period from January 1, 2006 in which we have an economic interest.

The following table shows the drilling and completion activity for the year ended December 31, 2006 with respect to the Pogo Properties. In the table, “gross” refers to the total number of wells in which Pogo had a working interest and “net” refers to gross wells multiplied by Pogo’s working interest in such wells. No development or exploratory wells were drilled on the Pogo Properties for the three month period ended March 31, 2007.

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	Year Ended December 31, 2006
	Gas		Oil		Dry		Total
Development
Gross		1		0		1		2
Net		0.2		0		0.5		0.7
Exploratory
Gross		1		0		0		1
Net		0.5		0		0		0.5

Properties

Below is a map showing the location of our significant properties, including properties acquired in the Pogo Acquisition.

Risk Factors

Investing in our common stock involves risks that include the speculative nature of natural gas and oil exploration, competition, volatile natural gas and oil prices and other material factors. You should read carefully the section entitled “Risk Factors” beginning on page 5 for an explanation of these risks before investing in our common stock.

Our Offices

Our company was founded in 2005 and is incorporated as an exempted company in Bermuda. Our principal executive offices are located at Canon’s Court, 22 Victoria Street, PO Box HM 1179, Hamilton HM EX, Bermuda, and our telephone number at that address is (441) 295-2244. Our website address is http://www.energyxxi.com.

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The Offering

Common stock offered by the selling shareholders	Up to 148,503,324 shares, consisting of the following:
	60,449,358 shares of common stock;
	73,053,966 shares of common stock issuable upon the exercise of common stock purchase warrants at an exercise price of $5.00 per share;
	5,000,000 shares of common stock issuable upon the exercise of unit purchase options at an exercise price of $6.60 per unit. Each unit purchase option is exerciseable into one common share and two common stock purchase warrants, each; and
	10,000,000 shares of common stock issuable upon the exercise of common stock purchase warrants at an exercise price of $5.00 per share issuable upon the exercise of unit purchase options.
Common stock outstanding prior to this offering	84,072,699 shares
Use of Proceeds	We will not receive any proceeds from the sale of common stock. Please read “Use of Proceeds.”
Alternative Investment Market (AIM) Symbol for Unrestricted Common Stock	“EXXI”
AIM Symbol for Restricted Common Stock	“EXXS”
Over-the-Counter Bulletin Board (OTCBB) Symbol	“EXXIF.OB”

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RISK FACTORS

Risks Associated with Our Securities

The market for our common stock and warrants is and may remain relatively illiquid.

Our common stock and warrants are admitted for trading on the Alternative Investment Market of the London Stock Exchange (AIM) and on the United States Over-the-Counter Bulletin Board (OTCBB). AIM is a market designed primarily for emerging or smaller companies. The rules of this market are less demanding than those of exchanges in the United States. Investments in shares traded on AIM is perceived to carry a higher risk than an investment in shares quoted on exchanges with more stringent listing requirements, such as the New York Stock Exchange, the American Stock Exchange or the NASDAQ Global Market. In addition, we may not always retain a listing on the AIM. In the United States, our common stock is not eligible for trading on any national or regional exchange. Our common stock is eligible for trading on the Over-the-Counter Bulletin Board (OTCBB). This market tends to be highly illiquid and there is a greater chance for market volatility for securities that trade on the OTCBB as opposed to securities that trade on a national exchange. We may not be able to list or thereafter maintain a listing of our securities on any national or regional exchange in the United States.

Risks Associated with Energy XXI Generally

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 significantly from that of prior owners.

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

Unlike other entities which are geographically diversified, we will not have the resources to diversify effectively 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 its 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 compared to our competitors that 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.

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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 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 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, such as the Pogo Properties, 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 significantly larger combined organization;

· coordinating geographically disparate organizations, systems and facilities;

· integrating corporate, technological and administrative functions;

· integrating internal controls and other corporate governance matters;

· diverting management’s attention from other business concerns;

· loss of key vendors from the acquired businesses;

· a significant 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 significant business activities are interrupted as a result of the integration process, our business could suffer.

Our operating performance, revenues and costs could be materially adversely affected if:

· we are not successful in completing the integration of the Pogo Properties into our operations;

· the integration takes longer or is more complex than anticipated; or

· we cannot operate the Pogo Properties as effectively as we anticipate.

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 April and July 2006 acquisitions, from the Pogo Acquisition 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 markets.

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Regulatory noncompliance with Pogo Properties may lower the initial production realized and increase the costs related to the Pogo Acquisition.

For the three month period ending March 31, 2007, the Pogo Properties produced approximately 6,400 Boed. The Pogo Properties have been the subject of a significant number of incidents of noncompliance by the MMS, which, in some cases, has resulted in the historical forced shut-in of production by the MMS for such noncompliance as well as additional shut-ins by Pogo as it sought to refocus its operations on compliance issues. To the extent that we do not provide sufficiently strong supervision to correct historical compliance issues, we may incur similar difficulties as the predecessor operator, may realize a lower level of production initially from the Pogo Properties than the estimated 7,400 Boed, and may realize a longer delay in reaching 7,400 Boed than anticipated.

We expect to incur significant charges relating to the integration plan that could materially and adversely affect our period-to-period results of operations.

We anticipate that from time to time we will incur charges to our earnings in connection with the integration of the Pogo Gulf of Mexico operations into our business. These charges will include expenses incurred in connection with recruiting and retaining new employees and increased professional and consulting costs. We are not yet able to quantify the costs or timing of the integration. Some factors affecting the cost of the integration include the training of new employees and the education of the field personnel to our approach to safety and regulatory compliance.

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 proven developed reserves. If we do not manage or are not capable of managing the commodity price risk of our production and energy prices fall significantly, 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 from the reserves.

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 significantly 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 significantly 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;

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· 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.

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 oil and 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 significant inaccuracies in these interpretations or assumptions could also materially effect 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, perhaps significantly. In addition, we may adjust estimates of proven 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 oil and gas reserves our future reserves and production will decline.

Our future oil and 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 proven reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proven 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% 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 significantly 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.

8

Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that 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 Minerals Management Service, or 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 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 significantly 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 (including the Pogo Properties) 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 significant 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 activities. Any such activities may be unsuccessful for many reasons, including adverse weather conditions (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Moreover, 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;

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· blow-outs and surface cratering;

· uncontrollable flows of gas, oil and formation water;

· 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 and 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 significant cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the shelf. As a result, a significant 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 which 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 which 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 acquired 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 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 always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

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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 gas wells or delay initial production for lack of a market or because of inadequacy or unavailability of gas 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 in respect of such properties.

As we carry out our planned drilling program, we will not serve as operator of all planned wells. We operate 79% 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, 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 as compared to 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 cease to be economically available in the future, which could adversely impact business prospects in the Gulf of Mexico and adversely impact our operations. If a significant 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.

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

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 significantly 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.

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.

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

Our success will depend to a significant 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 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.

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 its operations may be adversely affected. In addition, obtaining all necessary permits and approvals may necessitate substantial expenditures and may create a significant 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 United States and recent legislation in the United States 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 U.S.A., Inc. Energy XXI U.S.A., 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, all 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 United States and who render services to the U.S. business activities will be allocated as expenses of the U.S. subsidiaries.

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Various statements in this prospectus, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future reserves, production, revenues, income, and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, other similar expressions, or the statements that include those words are usually forward-looking statements.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

· our business strategy;

· our financial position;

· our cash flow and liquidity;

· integration of acquisitions, including the Pogo Acquisition;

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

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

· uncertainties in estimating our oil and gas reserves;

· replacing our oil and gas reserves;

· uncertainties in exploring for and producing oil and gas;

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

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

· disruptions capacity constraints in, or other limitations on the pipeline systems which deliver our gas and other processing and transportation considerations;

· competition in the oil and gas industry;

· our inability to retain and attract key personnel;

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

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

· other factors discussed under “Risk Factors.”

USE OF PROCEEDS

This prospectus relates to shares of our common stock that may be offered and sold from time to time by the selling stockholders. We will not receive any proceeds from the sale of shares of common stock in this offering. However, we will receive the sale price of any common stock we sell to the selling stockholders upon exercise of the warrants owned by the selling stockholders and we will receive the sale price of any unit purchase option exercised. We expect to use the proceeds received from the exercise of the warrants, if any, for general working capital purposes.

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SELECTED FINANCIAL INFORMATION

The following table sets forth our selected financial data as of March 31, 2007 (unaudited) and June 30, 2006 and for the nine months ended March 31, 2007 and the period from July 25, 2005 (inception) to September 30, 2005 (unaudited) and for the period from July 25, 2005 (inception) to June 30, 2006. The following table also presents our predecessor entity, Marlin, which we acquired in April 2006, as of December 31, 2005, 2004 and 2003 as well as for the three month period ended March 31, 2006 and each of the years in the three year period ended December 31, 2005. Our consolidated balance sheet data and statement of operations data at June 30, 2006 and the period from July 25, 2005 (inception) to June 30, 2006 are derived from our audited consolidated financial statements. The unaudited consolidated balance sheet data and statement of operations data at March 31, 2007 for the nine month period ended March 31, 2007 and for the period from July 25, 2005 (inception) to September 30, 2005 are derived from our unaudited financial statements which have been prepared in accordance with generally accepted accounting principles for interim financial information and the appropriate rules and regulations of the SEC. In the opinion of management, all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation have been included. Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. The combined balance sheet data and statement of operations data of our predecessor company at December 31, 2005 and 2004, the three month period ended March 31, 2006 and each of the years in the three year period ended December 31, 2005 are derived from the combined audited financial statements of our predecessor included elsewhere in this prospectus. The combined balance sheet data of our predecessor company (Marlin) at December 31, 2003 was derived from the audited financial statements of our predecessor company.  

	Nine Months Ended		Period from July 25, 2005(inception) to		Energy XXI Period from July 25, 2005		Predecessor (audited)
	March 31, 2007 (unaudited)		March 31, 2006 (unaudited)		(inception) to June 30, 2006 (audited)		Three Months Ended March 31, 2006		Year Ended December 31, 2005		Year Ended December 31, 2004		Year Ended December 31, 2003
	(in thousands except per share amounts)
Consolidated / Combined Statement of Operations Data:
Net revenues	$	222,568	$	—	$	47,112	$	46,441	$	164,122	$	101,982	$	25,738
Income (loss) from continuing operations	$	21,922	$	1,408	$	6,942	$	20,304	$	77,956	$	51,277	$	8,626
Income (loss) from continuing operations per common share
Basic	$	.26	$	.03	$	.14		—		—		—		—
Diluted	$	.26	$	.03	$	.12		—		—		—		—

	Energy XXI				Predecessor
	March 31,		June 30,		(audited)
	2007 (unaudited)		2006 (audited)		December 31, 2005		December 31, 2004		December 31, 2003
	(in thousands)
Consolidated / Combined Balance Sheet Data:
Total assets	$	1,068,368	$	643,971	$	375,028	$	291,187	$	96,113
Long term obligations (including current maturities of long-term debt)	$	602,485	$	248,303	$	36,035	$	33,448	$	3,833

The following table sets forth revenue and direct operating expenses of Castex for each of the years in the three year period ended June 30, 2006. The revenue and direct operating expense data are derived from the audited statements of revenue and direct operating expenses.

	Twelve Month Period Ended
	June 30, 2006		June 30, 2005		June 30, 2004
	(Restated)		(in thousands)
Revenues	$	61,225	$	5,517	$	220
Direct operating expenses	$	13,340	$	1,008	$	86

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The following table sets forth revenue and direct operating expenses for the Pogo Properties for each of the years in the three year period ended December 31, 2006 and for the nine months ended March 31, 2007 and 2006(unaudited). The revenue and direct operating expense data for the years ended December 31, 2006, 2005 and 2004 are derived from the audited statements of revenue and direct operating expenses.

	Nine Months Ended March 31,				Year Ended December 31,
	2007 (unaudited)		2006 (unaudited)		2006 (audited)		2005  (audited)		2004 (audited)
	(in thousands)
Revenues	$	101,686	$	112,770	$	148,718	$	179,476	$	192,938
Direct Operating Expenses	$	35,931	$	32,250	$	31,304	$	37,589	$	23,705

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

We are an independent energy company engaged in the acquisition, development, exploration and production of oil and natural gas reserves in the United States Gulf Coast and the Gulf of Mexico. Since our incorporation, 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 (the “Pogo Properties”) from Pogo Producing Company (the “Pogo Acquisition”). Our first and second major acquisitions closed on April 4, 2006 and July 28, 2006.

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 30 oil and gas fields with 118 producing wells. In July 2006, we acquired additional oil and gas working interests in 15 onshore and inland water Louisiana Gulf Coast fields from Castex. There are 49 producing wells in these fields we acquired from Castex. Pro forma for the acquisition of the Castex assets, our net proved reserve base totaled over 37.5 MMBoe as of June 30, 2006. Our average daily production for the three months ended March 31, 2007 was approximately 14,500 Boed, and we have averaged daily production for the first ten days of May 2007 in excess of 20,000 Boed. On June 8, 2007, we completed the Pogo Acquisition. The net proved reserve base of the Pogo Properties totaled 20.9 MMBoe as of December 31, 2006. We expect the Pogo Properties to add 7,400 Boed to our current production profile, not including the additional 1,500 Boed of production shut-in due to hurricane related damage, following an integration period and based on current operating assumptions.

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 related $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. We refer to the Pogo Acquisition, the $750 million senior notes offering, the repayment of second lien revolving credit facility and the amendment and restatement of our first lien revolving credit facility, all of which occurred on June 8, 2007, as the “Transactions.” As of March 31, 2007, after giving effect to the Transactions, we would have had $978.9 million of indebtedness outstanding, consisting of $750 million of notes offered and sold, $218.5 million under our first lien revolving credit facility, $10 million in put financings and $.4 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 we are obligated to make as of March 31, 2007 after giving effect to the Transactions. All amounts listed in the table below are categorized as liabilities on our balance sheet with the exception of lease payments for operating leases, performance bonds and outstanding letters of credit issued for performance obligations. Contractual obligations related to our credit facility include only payments of principal.

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	As of March 31, 2007 Payments Due by Period
	Total		1 year or less		2 - 3 years		4 -5 years		after 5 years
	(in thousands)
Contractual Obligations:
First lien revolver	$	218,457	$	—	$	—	$	218,457	$	—
10% Senior Notes due 2013		750,000								750,000
Put premium financing		10,026		6,290		3,736		—		—
Capital leases		445		94		244		107		—
Operating leases-drilling rig		17,524		17,524		—		—		—
Castex carried interest		8,084		8,084		—		—		—
Derivative instruments		4,073		4,073		—		—		—
Castex Lake Salvador Area of Mutual Interest		100		100		—		—		—
Operating lease-office		4,616		728		1,456		1,456		976
Performance bonds		42,150		41,050		1,100		—		—
Letters of credit		5,325		325		5,000		—		—
		1,060,800		78,268		11,536		220,020		750,976
Other Long-Term Obligations:
Asset retirement obligations		70,281		1,325		2,993		3,572		62,391
Total Contractual Obligations and Commitments	$	1,131,081	$	79,593	$	14,529	$	223,592	$	813,367

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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 and all of our other subsidiaries. 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% to 2.25% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.25% to 1.25%. 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% reduction. The credit facility is secured by mortgages on at least 85% of the value of our proved reserves. Our initial borrowing base under the facility was $425 million, of which approximately $267.5 million was borrowed as of June 8, 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, 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.

The Notes

On June 8, 2007 our subsidiary, Energy XXI Gulf Coast, Inc., completed a $750 million offering of 10% 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. The indenture contains customary covenants and events of default.

Put Financings

We finance puts that we purchase with our hedge providers. All 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 May 31, 2007, our hedge financing totaled $8.9 million. We expect the amount of hedge financing to increase following the Pogo Acquisition from current levels, as we intend to apply a similar hedging strategy with regard to the Pogo Properties.

Capital Resources

The capital budget for the exploration and development drilling program in fiscal 2008 is approximately $300 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 a significant acquisition opportunity arises, we may also access public markets to issue additional debt and/or equity securities. Cash was used primarily to fund acquisitions and exploration and development expenditures during the period from July 25, 2005 (inception) to June 30, 2006. At June 30, 2006, we had a working capital surplus of $121 million. At March 31, 2007, we had a working capital surplus of $53 million.

Operating Activities

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Nine Month Period Ended March 31, 2007 compared to the period from July 25, 2005 (inception) to March 31, 2006 

For the nine month period ended March 31, 2007, we generated net income of $21.9 million which included the results of the Castex acquisition on July 28, 2006. Commodity prices, production volumes and operating expenses are the key factors changing operating results in the future. Changes in commodity prices also impact the results of our derivative activities. In addition, the level of capital expenditures will impact accounts payable. At March 31, 2007, we continued to maintain an adequate level of working capital, excluding cash balances, of $43.1 million. However, a significant portion of this working capital is transitory as it includes $15.5 million in the current portion of the fair value of our derivative instruments.

For the period from July 25, 2005 (inception) to March 31, 2006, we had no revenues and generated interest income of $4.7 million and interest expense of $1.5 million. We had general and administrative expenses of $1.8 million and depreciation, depletion and amortization expense of $40,000.

Period from July 25, 2005 (inception) to June 30, 2006

During the period from July 25, 2005 (inception) to June 30, 2006, we transitioned from being an acquisition corporation which had no operating revenues to an operating company with the completion of the Marlin acquisition on April 4, 2006. For the year, we generated $6.9 million of net income, the bulk of which was attributable to operating activities after the completion of the acquisition. Commodity prices, production volumes and operating expenses are the key factors changing operating results in the future. Non-cash charges, of which depletion, depreciation, and amortization of $20.4 million was the largest, enabled us to generate $30.5 million in cash flows from operating activities, prior to changes in operating assets and liabilities. With the Marlin acquisition, there was a large build-up of working capital, excluding cash balances, totaling approximately $58.3 million comprised of $110.8 million of non-cash current assets and $52.5 million of current liabilities as the company established a level consistent with that needed to support the operations. However, a significant portion of this working capital is transitory as it includes a $39.8 million insurance receivable which will be eliminated once all insurance repairs associated with damage from hurricanes Rita and Katrina are completed and the insurance claims are paid.

Net cash provided by operating activities was $12.1 million for the period from July 25, 2005 (inception) to June 30, 2006. This increase was primarily a result of $6.9 million in net income and $20.4 million of depreciation, depletion and amortization and a $14.3 million increase in accounts payable and other liabilities offset by a $32.7 million increase in accounts receivable, prepaid expenses and other current assets. In addition to fluctuations in other operating assets and liabilities that are caused by the timing of cash receipts and disbursements, commodity prices, production volumes and operating expenses are the key factors driving changes in operating cash flows.

Investing Activities

Nine month period ended March 31, 2007 compared to the period from July 25, 2005 (inception) to March 31, 2006

Net cash used in investing activities for the nine month period ended March 31, 2007 was $550.7 million which included $302.5 million for the acquisition of Castex and $251.0 million in capital expenditures related to the Marlin and Castex properties. Cash used in investing activities for the period from July 25, 2005 (inception) to March 31, 2006 consisted of $384,000 in capital expenditures and a $10 million deposit made toward the Marlin acquisition.

Period from July 25, 2005 (inception) to June 30, 2006

Net cash used in investing activities for the period from July 25, 2005 (inception) to June 30, 2006 included $448.4 million for the purchase of oil and gas properties which closed on April 4, 2006, $19.1 million to fund our capital expenditure program including investments in other property and equipment, $3.2 million net investment in certain hedging contracts and a $10 million escrow deposit for an acquisition of oil and gas properties which was closed in July 2006.

Financing Activities

Nine month period ended March 31, 2007 compared to the period from July 25, 2005 (inception) to March 31, 2006 

Net cash provided by financing activities for the nine month period ended March 31, 2007 was $339.7 million which included $364 million in proceeds from the first and second lien facility, $13.1 million in proceeds from the issuance of common stock and payments on the financed puts of $7.0 million. Payments on the first lien and second revolver totaled $24.6 million and debt issue costs totaled $4.8 million. Net cash provided by financing activities for the period from July 25, 2005 (inception) to March 31, 2006 included $300 million in proceeds from the issuance of common stock (less $21 million in stock issuance cost) and $14.2 million in proceeds from long-term debt.

Period from July 25, 2005 (inception) to June 30, 2006

Net cash provided by financing activities for the period from July 25, 2005 (inception) to June 30, 2006 include $365.3 million in proceeds from the issuance of equity securities (net of payments to repurchase and cancel shares), $192.5 million in borrowings under our credit facilities which was offset by $22.3 million in payments for stock issuance related costs.

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Drilling Activity

The following table shows our drilling and completion activity for the nine month period ended March 31, 2007 and for the period from July 25, 2005 (inception) to June 30, 2006. Prior to our first acquisition on April 4, 2006, we had no reserves or development or exploratory activity. Except as noted below, the table reflects only the activity during our period of ownership of the properties. In the table, “gross” refers to the total number of wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest in such wells.

	Nine Months Period Ended March 31, 2007								Period from July 25, 2005 to June 30, 2006(1)
	Gas		Oil		Dry		Total		Gas		Oil		Dry		Total
Development
Gross		8		4		4		16		3		5		2		10
Net		5.7		4		4		13.7		1.8		5		1.5		8.3
Exploratory
Gross		5		3		4		12		—		—		—		—
Net		2.8		2.1		.8		5.7		—		—		—		—

(1) Includes drilling activity for the period from January 1, 2006 in which we have an economic interest.

Productive Wells

The following table presents the total gross and net productive wells at March 31, 2007:

	At March 31, 2007
	Oil Wells				Natural Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Onshore		24		19.7		61		19.7		85		39.4
Offshore		51		48.1		31		13.3		82		61.4
Total		75		67.8		92		33		167		100.8

Acreage

The following table summarizes our estimated developed and undeveloped leasehold acreage as of March 31, 2007. Developed acreage is assigned to producing wells. Undeveloped acreage is acreage held under lease, permit, contract or option that is not assigned to a producing well, including leasehold interests identified for exploratory drilling. Gross acres refers to the total number of acres in which we own a working interest. Net acres refers to gross acres multiplied by our fractional working interest. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

	At March 31, 2007
	Developed Acres				Undeveloped Acres
	Gross		Net		Gross		Net
Onshore		47,684		29,922		99,277		49,978
Offshore		208,227		91,037		49,174		20,882
Total		255,911		120,958		148,451		70,860

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The following table summarizes our onshore and offshore undeveloped acreage expiring during the periods ended March 31, 2008, 2009 and 2010.

	March 31,
	2008				2009				2010
	Gross		Net		Gross		Net		Gross		Net
Onshore		15,185		6,804		8,677		3,705		5,879		2,814
Offshore		28,750		9,727		5,000		2,937		—		—
Total		43,935		16,531		13,677		6,642		5,879		2,814

Results of Operations

Revenues

For the nine month period ended March 31, 2007, oil and gas revenue was $222.6 million due to the acquisition of Marlin on April 4, 2006 and the acquisition of Castex on July 28, 2006. We had no revenues for the period from July 25, 2005 (inception) to March 31, 2006.

Period from July 25, 2005 (inception) to June 30, 2006

For the period from July 25, 2005 (inception) to June 30, 2006, oil and gas revenue was $47.1 million. Production commenced on April 4, 2006 with the acquisition of certain oil and gas properties.

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The following table presents our significant operational information for the nine month period ended March 31, 2007 and the period from July 25, 2005 (inception) to June 30, 2006.

Operational Information

	Nine Months Ended March 31, 2007		Period from July 25, 2005 (inception) to June 30, 2006
Oil, gas and NGL sales, excluding $22.9 million and $1.4 million in a gains related to the impact of hedging program for the nine months ended March 31, 2007 and the period from July 25, 2005 (inception) to June 30, 2006, respectively. (in thousands)	$	199,679	$	45,685
Gas sales—MMcf		12,911.70		2,458.90
Average sales price per Mcf	$	6.86	$	6.48
Oil sales—MBbls		1,841.55		442.10
Average sales price per Bbl	$	59.73	$	66.70
NGL sales—MBbls		25.24		4.30
Average NGL sales price per Bbl	$	42.43	$	60.67
Production and operating costs (excluding depreciation, depletion and amortization) (in thousands)	$	36,547	$	9,986
Production and operating costs per equivalent Bbl	$	9.10	$	11.66
Depreciation, depletion and amortization (in thousands)	$	88,055	$	20,357
Net income (in thousands)	$	21,922	$	6,942
Working capital (in thousands)	$	53,237	$	120,668

Costs and Expenses

Nine month period ended March 31, 2007 compared to the period from July 25, 2005 (inception) to March 31, 2006

Our lease operating expense, depreciation, depletion and amortization of oil and gas properties and general and administrative expense were $33.6 million, $88.1 million and $26.5 million, respectively, for the nine month period ended March 31, 2007. During the period from July 25, 2005 (inception) to March 31, 2006, we had general and administrative expenses of $1.8 million and depreciation, depletion and amortization expense of $40,000. The increase in expenses during the nine month period ended March 31, 2007 is a result of the Marlin and Castex property acquisitions on April 4, 2006 and July 28, 2006, respectively. The decline in production and operating costs per BOE reflect lower operating costs associated with the Castex acquisition which is primarily gas that generally has lower production costs.

Period from July 25, 2005 (inception) to June 30, 2006

Our lease operating expenses and depreciation, depletion and amortization of oil and gas properties of $9.9 million of $20.2 million, respectively, for the period from July 25, 2005 (inception) to June 30, 2006 relate to expenses associated with the Marlin acquisition on April 4, 2006 through June 30, 2006. General and administrative expenses of $4.4 million for the period from July 25, 2005 (inception) to June 30, 2006, net of amounts capitalized directly related to oil and gas property acquisition, exploration and development of $1.9 million, include employee salaries and related benefits, insurance and legal and other professional fees.

Other Income and Expense

Nine month period ended March 31, 2007 compared to the period from July 25, 2005 (inception) to March 31, 2006 

Our interest expense for the nine month period ended March 31, 2007 of $39.7 million included $32.4 million of interest related to the first lien revolver and second lien facility, $6.0 million in debt issue cost related to the first lien revolver and second lien facility, and $1.3 million related to the financing of certain derivative instruments. We incurred additional indebtedness during the nine month period ended March 31, 2007 due to the acquisition of Castex on July 28, 2006.

For the period from July 25, 2005 (inception) to March 31, 2006 we had interest income of $4.7 million and interest expense of $1.5 million.

Our interest income of $1.6 million during the nine month period ended March 31, 2007 related to the investment of cash funds.

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Our tax expense of $12.0 million for the nine month period end March 31, 2007 is a result of taxes on income at an effective rate of 35.33%. The effective tax rate has increase from the effective tax rate experienced for the period from July 25, 2005 to June 30, 2006 of 19.9% as a greater portion of our income was subject to United States taxes.

Period from July 25, 2005 (inception) to June 30, 2006

Interest income of $5 million includes earning on the proceeds from our initial offering in October 2005 until the funds were utilized for the purchase of Marlin in April 2006. Interest expense of $7.9 million relates to interest incurred on our First Lien Revolver, Second Lien Facility and Note Purchase Agreement related to the Marlin acquisition in April 2006.

Our tax expense of $1.7 million for the three month period from July 25, 2005 (inception) to June 30, 2006 is a result of taxes on income at an effective rate of 19.9%.

Critical Accounting Policies and Estimates

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 judgement. Our most sensitive accounting policy affecting our financial statements is our oil and gas reserves, which are highly sensitive to changes in oil and gas prices that have been volatile in recent years. Although decreases in oil and gas prices are partially offset by our hedging program, to the extent reserves are adversely impacted by reductions in oil and gas prices, we could experience increased depreciation, depletion and amortization expense in future periods.

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 significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, 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 depreciation rates utilized by us. We cannot predict the types of reserve revisions that will be required in future periods.

The following table summarizes our sensitivities to changes in oil and gas prices at June 30, 2006:

	Oil (Bbl)		Gas (MMbtu)
Average prices in June 30, 2006 reserve reports (1)	$	70.75	$	6.09
Change in pro forma June 30, 2006 standardized measure resulting from a 10% change in prices, before consideration of the impact of the hedging program (in thousands) (1)	$	45,293	$	40,752

(1) Includes our pro forma reserves at June 30, 2006 after giving effect to the Marlin and Castex acquisitions.

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Oil and Gas Properties. We use the full cost method of accounting for exploration and development activities as defined by the 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 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.

Properties and equipment include costs that are excluded from costs being depleted or amortized. Oil and natural gas 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 property has been evaluated.

We evaluate the impairment of our evaluated oil and gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and gas properties are a significant factor in determining the full cost ceiling limitation of capital costs. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and gas reserves could be subject to significant revisions due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict. At March 31, 2007 and June 30, 2006, a 10% decrease in oil and gas prices would not impact our full cost ceiling limitation test.

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 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 require 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.

If our estimate of the future abandonment liabilities recorded at the acquisition date of Marlin and Castex were understated by 10%, the impact would be an increase in the Marlin and Castex oil and gas properties cost and asset retirement obligations of $3.7 million and $0.6 million, respectively, and would be recognized in the statement of operations in future periods through depreciation, depletion and amortization expense and accretion expense.

Derivative Instruments. We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements in order to manage the price risk associated with future crude oil and natural gas production. Such derivatives are accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), 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.

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.

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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 in the locally indexed price received for daily physical deliveries of the hedged quantities and the index price used in hedge settlement, and changes in grade and quality factors of the hedges oil and gas production which 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:

	March 31, 2007						June 30, 2006
	Oil (Bbl)			Gas (MMbtu)			Oil (Bbl)			Gas (MMbtu)
Average prices used in determining fair value	$	69.07		$	8.48		$	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):		($24,248	)		($22,929	)		($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 after tax would have increased or (decreased) for the period from July 25, 2005 (inception) to June 30, 2006 and the nine months ended March 31, 2007 by ($4.7 million) and $5.9 million if our oil and natural gas hedges did not qualify as cash flow deferral hedges under SFAS No. 133.

Income Taxes. We account for income taxes in accordance with Statement of Financial Accounting Standards (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 by management due to timing and the impact of future events on when income taxes 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 financial statements.

New Accounting Standards

Accounting for Fair Value Measurements.In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157 Fair Value Measurements (“SFAS No. 157”). SFAS 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.

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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 FASB Statement 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 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 FASB Statement No. 109 Accounting for Income Taxes (“SFAS 109”). 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. FIN 48 is effective for fiscal years beginning after December 15, 2006.

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 FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and FASB 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. We are in the process of determining the effect, if any, the adoption of this FSP will have on its consolidated financial statements.

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.

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

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

As of March 31, 2007, we had the following derivative contracts outstanding:

Puts(1)	Quantity		Price		March 31, 2007 Fair Value
					(in thousands)
Crude Oil (MBbls)
April 1, 2007 to March 31, 2008		160	$	60.00	$	352
April 1, 2008 to March 31, 2009		83	$	60.00		183
Natural Gas (MMBtus)
April 1, 2007 to March 31, 2008		7,560	$	8.00		4,651
April 1, 2008 to March 31, 2009		4,190	$	8.00		2,926
					$	8,112

Swaps	Quantity		Price		March 31, 2007 Fair Value
					(in thousands)
Crude Oil (MBbls)
April 1, 2007 to March 31, 2008		820	$	69.08 - 72.00		9,275
April 1, 2008 to March 31, 2009		812	$	69.08 - 71.96		(31	)
April 1, 2009 to March 31, 2010		489	$	69.24 - 71.06		215
Natural Gas (MMBtus)
April 1, 2007 to March 31, 2008		11,286	$	7.00 - 9.84		3,880
April 1, 2008 to March 31, 2009		6,770	$	8.95 - 9.39		2,018
April 1, 2009 to March 31, 2010		3,020	$	7.00 - 9.02		375
						15,732

Collars	Quantity		Price		March 31, 2007 Fair Value
					(in thousands)
Crude Oil (MBbls)
April 1, 2007 to March 31, 2008		307	$	60 - 78		(285	)
April 1, 2008 to March 31, 2009		166	$	60 - 78		(154	)
Natural Gas (MMBtus)
April 1, 2007 to March 31, 2008		2,440	$	8.00 - 11.10		1,093
April 1, 2008 to March 31, 2009		1,260	$	8.00 - 11.10		562
						1,216

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Three Way Costless Collars	Quantity		Price		March 31, 2007 Fair Value
					(in thousands)
Crude Oil (MBbls)
April 1, 2007 to March 31, 2008		1018	$	45 / 65 / 72.9		(6,277	)
April 1, 2008 to March 31, 2009		268	$	55 / 65 / 72.9		(651	)
April 1, 2009 to March 31, 2010		59	$	55 / 65 / 72.9		(143	)
Natural Gas (MMBtus)
April 1, 2007 to March 31, 2008		1,820	$	6 / 8 / 10		(205	)
April 1, 2008 to March 31, 2009		1,580	$	6 / 8 / 10		(178	)
April 1, 2009 to March 31, 2010		1,950	$	6 / 8 / 10		(220	)
						(7,674	)

(1) Included in natural gas puts are 6,910 MMBtus and 3,840 MMBtus of $6.00 to $8.00 put spreads for the years ended March 31, 2008 and 2009, respectively.

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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% to 5.75%. At March 31, 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 $(1.4) 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.

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BUSINESS

General

Energy XXI (Bermuda) Limited is an independent energy company engaged in the acquisition, development, exploration and production of oil and natural gas reserves in the United States Gulf Coast and the Gulf of Mexico. 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. Since our incorporation, 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 (the “Pogo Properties”) from Pogo Producing Company (the “Pogo Acquisition”). Our first and second major acquisitions closed on April 4, 2006 and July 28, 2006. In October 2005, we completed a $300 million initial public offering of common stock and warrants on the “Alternative Investment Market” of the London Stock Exchange.

We operate geographically focused producing reserves and target the acquisition of oil and gas properties that lend themselves to an intensive exploitation program to significantly increase production and ultimate recovery of reserves, or that alternatively offer the potential for using reprocessed seismic data to identify previously overlooked exploration opportunities. Approximately two-thirds of our capital is currently spent on exploitation with the balance of our capital expenditures split between lower risk exploration opportunities and higher impact exploration plays. Since acquiring our largest field in April 2006, the South Timbalier 21 field, and employing our focused exploitation program, we have realized a 90% increase in daily production levels from inception to the month ended March 31, 2007. Production from this large legacy field is currently at a 21-year high. Our exploitation of this field has involved the drilling of 13 new wells and 10 workovers of existing wells through March 31, 2007. We have 19 remaining identified proven well opportunities in South Timbalier 21 and anticipate selectively employing our exploitation strategy to our other offshore assets.

Our high quality assets are located in mature and predictable fields. As of March 31, 2007, after giving effect to the Pogo Acquisition, we will operate or have an interest in 284 producing wells over 283,000 net acres in 73 fields. All of our properties are located on the Gulf Coast and in the Gulf of Mexico, with approximately 60% of our proved reserves being offshore. All of the Pogo Properties are located offshore. This concentration facilitates our ability to manage the operated fields efficiently, and our high number of wellbore locations provides significant diversification of our reserves. We believe managing our assets is a key strength, and we operate 79% of our properties. We utilize an exploitation strategy with respect to our offshore Gulf of Mexico assets to enhance production, from our existing reserve base, as evidenced by our success with the South Timbalier 21 field. In the Gulf Coast, our strategy is to acquire, merge and reprocess seismic data to identify previously overlooked exploration opportunities. We have a significant seismic database covering approximately 2,400 square miles from our existing operations. Through the exploration of our existing asset base, we have identified at least 109 development and exploration opportunities. We believe the Pogo Properties will lend themselves well to our aggressive exploitation strategy to increase production from mature legacy fields and will provide us extensive incremental exploration opportunities within our core geographic area.

We actively manage price risk and hedge a high percentage of our proved developing producing reserves to enhance revenue certainty and predictability. We intend to apply the same strategy with regard to the Pogo Properties. Our disciplined hedging 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 hedging 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”), and their Gulf of Mexico assets consisting of working interests in 30 oil and gas fields with 118 producing wells. In July 2006, we acquired additional oil and gas working interests in 15 onshore and inland water Louisiana Gulf Coast fields from affiliates of Castex Energy, Inc. (“Castex”). There are 49 producing wells in these fields we acquired from Castex. Pro forma for the acquisition of the Castex assets, our net proved reserve base totaled over 37.5 MMBoe as of June 30, 2006. Our average daily production for the three months ended March 31, 2007 was approximately 14,500 Boed, and we have averaged daily production for the first ten days of May 2007 in excess of 20,000 Boed. On June 8, 2007, we completed the Pogo Acquisition. The net proved reserve base of the Pogo Properties totaled 20.9 MMBoe as of December 31, 2006. We expect the Pogo Properties to add 7,400 Boed to our current production profile, not including the additional 1,500 Boed of production shut-in due to hurricane related damage, following an integration period and based on current operating assumptions.

We intend to grow our reserve base and increase production through strategic acquisitions of oil and natural gas properties, our drilling program and the further optimization of production.

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Proved Reserves and Production Summary

The reserve reports associated with the properties we acquired in the Marlin and Castex acquisitions were prepared as of June 30, 2006 and the reserve report associated with the Pogo Properties was prepared as of December 31, 2006. Because these reserve reports were prepared on different dates, the proved reserves set forth therein are not comparable to each other as they are calculated utilizing differing assumptions specific to the respective dates of these reports, including commodity prices. As such, we believe it is not meaningful to present, and therefore we have not presented, the combined or pro forma information of our properties and the Pogo Properties derived from these reserve reports.

	Energy XXI			Pogo Properties
Proved Reserve Summary:
Proved reserves		37.5 MMBoe(1)	)		20.9 MMBoe(2)	)
Percentage oil and natural gas liquids		40	%		70	%
Percentage offshore		60	%		100	%

			Combined Energy XXI and Pogo Properties
Production Summary:
Average daily production(3)	14,500	6,400	20,900
Producing wells	167	117	284

(1) Based on June 30, 2006 reserve reports completed by Netherland, Sewell and Associates, Inc. and Miller and Lents, Ltd. for the Marlin and Castex acquisitions, respectively.

(2) Based on a December 31, 2006 reserve report completed by Ryder Scott Company, L.P.

(3) Average Boed for the quarter ended March 31, 2007. Average daily production for the Pogo Properties is based on March 31, 2007 lease operating statements provided to us by Pogo.

Drilling Activities

The following table shows our drilling and completion activity for the nine month period ended March 31, 2007 and for the period from July 25, 2005 (inception) to June 30, 2006. Prior to our first acquisition on April 4, 2006, we had no reserves or development or exploratory activity. Except as noted below, the table reflects only the activity during our period of ownership of the properties. In the table, “gross” refers to the total number of wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest in such wells.

	Nine Months Period Ended March 31, 2007								Period from July 25, 2005 to June 30, 2006(1)
	Gas		Oil		Dry		Total		Gas		Oil		Dry		Total
Development
Gross		8		4		4		16		3		5		2		10
Net		5.7		4		4		13.7		1.8		5		1.5		8.3
Exploratory
Gross		5		3		4		12		—		—		—		—
Net		2.8		2.1		.8		5.7		—		—		—		—

(1) Includes drilling activity for the period from January 1, 2006 in which we have an economic interest.

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The following table shows the drilling and completion activity for the year ended December 31, 2006 with respect to the Pogo Properties. In the table, “gross” refers to the total number of wells in which Pogo had a working interest and “net” refers to gross wells multiplied by Pogo’s working interest in such wells. No development or exploratory wells were drilled on the Pogo Properties for the three month period ended March 31, 2007.

	Year Ended December 31, 2006
	Gas		Oil		Dry		Total
Development
Gross		1		0		1		2
Net		0.2		0		0.5		0.7
Exploratory
Gross		1		0		0		1
Net		0.5		0		0		0.5

Properties

Below is a map showing the location of our significant properties, including properties acquired in the Pogo Acquisition.

Marketing and Customers

We market substantially all of our oil and natural gas production from the properties we operate. We also market over 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 lists customers accounting for more than 10% of our total revenues for period from July 25, 2005 (inception) to June 30, 2006.

Customer	Percent of Total Revenue
Chevron, USA		57	%
Louis Dreyfus Energy Services, LP		14	%

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 customers listed above. Therefore, we believe that the loss of either of the customers 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.

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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.

We expect to market substantially all of our oil and natural gas production from the Pogo Properties to Shell Trading US Company.

Competition

We encounter intense competition from other oil and gas companies in all areas of their operations, including the acquisition of producing properties and proven 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 than us 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.

Governmental Regulation

General

Our operations are affected by extensive and continually changing regulation respecting the oil and gas industry. Many departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and gas industry and its individual participants. The Federal Energy Regulatory Commission, or FERC, regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or the NGA, and the Natural Gas Policy Act of 1978. In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas, crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. The regulatory burden on the oil and gas industry increases the costs of doing business and, consequently, will affect our profitability. We do not believe we are affected in a significantly different manner by these regulations than are our competitors.

Regulation and Transportation of Natural Gas

Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically have limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis. In many instances, Order No. 636 and related initiatives have substantially reduced or eliminated the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. We cannot predict what further action the FERC will take with regard to its regulations and open-access policies, whether the FERC will change its current policies, or whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects our competitors.

The Outer Continental Shelf Lands Act, or OCSLA, under which the FERC has certain limited authority, requires that all pipelines operating on or across the Outer Continental Shelf, or OCS, provide open access, non-discriminatory transportation service. There are currently no regulations implemented by the FERC under its OCSLA authority respecting entities outside the reach of the FERC’s NGA jurisdiction. The Minerals Management Service, or MMS, has asked for comments on whether it should implement regulations under its OCSLA authority to ensure open and non-discriminatory access on gathering systems and production facilities on the OCS. Although we have no way of knowing whether the MMS will proceed with implementing regulations of this nature, we do not believe that any action taken under the OCSLA by either the FERC or the MMS will affect us in a way that materially differs from the way it affects other oil and natural gas exploration and production companies.

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The FERC does not have jurisdiction over gathering service performed in state waters, the relevant states do. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our cost of getting gas to point-of-sale locations. With regard to the state regulation of gathering service, the basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive from sales of our natural gas. Because such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that state regulation of intrastate natural gas pipelines will not affect our operations in any way that is materially different from the operations of our competitors.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Oil Price Controls and Transportation Rates

Sales of crude oil, condensate and natural gas liquids by us are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service may be subject to FERC jurisdiction under the Interstate Commerce Act, or ICA, and/or FERC and MMS regulation under the OCSLA. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.

The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC’s regulation of natural gas pipelines under the NGA. FERC-regulated pipelines that transport crude oil, condensate, and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipelines subject to FERC regulation under the ICA, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Oil pipelines that are subject to OCSLA jurisdiction must adhere to the open-access and non-discrimination mandates of the OCSLA. Pursuant to Order No. 561, issued in October 1993, the FERC implemented an indexing methodology subjecting oil pipeline rates to adjustment based on changes to the Producer Price Index for Finished Goods, or PPI, minus one percent. The FERC’s indexing methodology is subject to review every five years. We have no way of knowing what further changes the FERC may make to its indexing methodology as a result of subsequent reviews. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge a market-based rate if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. In March 2006, the FERC changed the rate indexing methodology to the PPI plus 1.3 percent.

With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines by the FERC. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests. Complaints or protests have been infrequent and are usually resolved informally.

We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate, or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate, and natural gas liquids producers or marketers.

Regulation of Oil and Natural Gas Exploration and Production

The production of oil and natural gas in the United States and the Gulf of Mexico is subject to regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal regulatory requirements include obtaining permits prior to commencing drilling operations, securing bonds or other financial assurances to ensure compliance with applicable regulatory requirements, and submitting periodic reports concerning operations. Many coastal states have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, the spacing of wells, and the plugging and abandonment of wells and removal of related production equipment. These regulations can limit the amount of oil and natural gas produced, limit the number of wells, or limit the locations at which drilling operations may be conducted.

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A substantial portion of our operations is located on federal oil and natural gas leases, which are administered by the MMS pursuant to the OCSLA. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed MMS regulations and orders that are subject to interpretation and change by the MMS.

For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas and the burning of liquid hydrocarbons. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities.

To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. The MMS also administers the collection of royalties due on oil and natural gas produced from federal offshore leases. The amount of royalties due is based on MMS regulations and upon the terms of the individual oil and natural gas leases. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could have a material adverse affect on our financial condition and results of operations.

In our first year of operations in the Gulf of Mexico, we were named as a Safety Award for Excellence Finalist in 2006 by the MMS. However, the Pogo Properties have been the subject of a significant number of incidents of noncompliance by the MMS, which, in some cases, has resulted in the historical forced shutdowns by Pogo as it sought to refocus its operations on compliance issues. We intend to apply our high safety standards to cause the Pogo Properties to meet all MMS requirements, consistent with our other properties.

Environmental Regulations

Oil and natural gas exploration and production operations are subject to numerous, stringent and complex laws and regulations at the federal, state and local levels governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

· require acquisition of a permit before exploration, drilling and production operations commence;

· restrict the types, quantities and concentrations of various materials that can be released into the environment in connection with drilling and production activities; and

· limit or prohibit construction or drilling activities in certain ecologically sensitive and other protected areas.

Compliance with such laws and regulations can be costly and noncompliance can result in substantial civil and even criminal penalties. Some environmental laws impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault. Moreover, public interest in the protection of the environment has increased dramatically in recent years. Offshore drilling in some areas has been opposed by environmental groups and, in other areas, has been restricted. Our operations could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general. The following provides a general discussion of some of the significant environmental laws and regulations that will be impacting our exploration and production activities.

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The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” and “operator” of the site where the release occurred, past owners and operators of the site, and companies that disposed or arranged for the disposal of hazardous substances found at the site. Responsible parties under CERCLA may be liable for the costs of cleaning up hazardous substances that have been released into the environment and for damages to natural resources. Additionally, it is not uncommon for third parties to assert claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment.

The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, or RCRA, is the principal federal statute governing the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas.

The federal Oil Pollution Act of 1990, or OPA, and regulations thereunder impose liability on “responsible parties” for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA limits liability for offshore facilities to all removal costs plus up to $75 million in other damages. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up. The OPA also requires the lessee or permittee of an offshore area in which a covered offshore facility is located to provide financial assurance in the amount of $35 million ($10 million if the offshore facility is located in state waters) to cover liabilities resulting from an oil spill. The amount of financial assurance required under the OPA may be increased up to $150 million depending on the risks presented by the quantity or quality of oil that is handled by a facility. Failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions.

The federal Water Pollution Control Act, or the Clean Water Act, imposes restrictions and controls on the discharge of produced waters and other oil and gas pollutants into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions may be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. Certain state regulations and general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into certain coastal and offshore waters. The Clean Water Act provides for administrative, civil and criminal penalties for unauthorized discharges of oil and other pollutants, and imposes liability on responsible parties for the costs of cleaning up any environmental damage caused by the release and for any resulting natural resource damages. Comparable state statutes impose liabilities and authorize penalties in the case of an unauthorized discharge of petroleum or its derivatives, or other pollutants, into state waters.

The federal Clean Air Act, and associated state laws and regulations, restrict the emission of air pollutants from many sources, including facilities involved in oil and natural gas exploration and production operations. New facilities are generally required to obtain permits before operations can commence, and new or existing facilities may be required to incur certain capital expenditures to install air pollution control equipment in connection with obtaining and maintaining operating permits and approvals. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations.

Although emissions of carbon dioxide, a common byproduct of the combustion of oil and gas, are not currently regulated under the federal Clean Air Act, the United States Supreme Court recently determined that greenhouse gases, including carbon dioxide, are air pollutants and that the EPA may regulate these pollutants from motor vehicles without further Congressional action. It is possible that any EPA regulation of greenhouse gases as an air pollutant ultimately could extend to stationary emission sources, in addition to motor vehicles. In addition, several states have recently adopted legislation to restrict emissions of carbon dioxide and other “greenhouse gases,” including methane, that may contribute to global warming. Although our operations are not located in any state where such restrictions have been adopted, it is possible that our operations could become subject to such restrictions in the future. In addition, the widespread adoption of restrictions on emissions of greenhouse gases could adversely affect demand for our products.

The federal Endangered Species Act, the federal Marine Mammal Protection Act, and similar federal and state wildlife protection laws prohibit or restrict activities that could adversely impact protected plant and animal species or habitats. Oil and natural gas exploration and production activities could be prohibited or delayed in areas where such protected species or habitats may be located, or expensive mitigation may be required to accommodate such activities.

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Insurance

As a general matter, 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. Specifically, we maintain windstorm insurance coverage but do not maintain business interruption insurance. Windstorm coverage covers damage to our facilities from “named storms” as defined by the National Oceanic and Atmospheric Administration. Currently, we have total windstorm coverage for all our assets, except for the properties we acquired in July 2006, equal to $72.5 million for each named storm and in the aggregate, subject to a $7.5 million deductible for each named storm. In connection with the Transactions, we will be obligated to increase our windstorm insurance coverage to at least $125 million for each named storm and in the aggregate. Windstorm insurance costs have increased during the past year. Instead of business interruption insurance, we rely on our own liquidity to mitigate risks caused by reduced coverage. We intend to maintain additional liquidity each hurricane season.

The oil and gas properties that we acquired from Marlin were damaged by both hurricanes Katrina and Rita but were covered in part by insurance. The insurance coverage is an indemnity program that provides for reimbursement after funds are expended. As of June 30, 2006, we had a $39.8 million insurance receivable. On January 19, 2007, we entered in to a global settlement of $38.8 million which covered all previously unreimbursed amounts. All but $0.1 million of this amount was received in the third quarter of 2007. Any additional work will be at our expense.

Currently, most of the repairs at our properties have been completed but substantial debris remains to be removed. Certain repairs and debris removal have been delayed due to weather and a lack of adequate equipment and manpower. We expect the cost of repairs and clean up regarding our existing properties and the Pogo Properties will be approximately $25 million. We have not yet established a set schedule by which we anticipate making these repairs.

Risk Management Program

We actively manage price risk and hedge a portion of our future production with an options strategy to enhance the likelihood of a return on capital, while maintaining potential for future benefit if prices rise. In general, we hedge a high percentage of our proved developed producing reserves. Our disciplined hedging 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.

Employees

As of June 19, 2007, we had 80 employees, none of which are represented by organized labor. We rely upon third party services to maximize the efficiency of our organization and activities related to our operated properties. We consider our relations with our employees to be good.

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PROPERTIES

Oil and Gas Properties

Below are descriptions of our significant properties, including the significant properties we acquired as part of the Pogo Acquisition, and a map showing their locations.

South Timbalier 21 Field. The South Timbalier 21 field is located six miles offshore of Lafourche Parish, Louisiana in approximately 50 feet of water. The field consists of Outer Continental Shelf, or OCS, blocks South Timbalier 21, 22, 23, 27 and 28 as well as two state leases. South Timbalier 21 consists primarily of oil reserves and we have a 100% working interest in the field. The field is bounded on the north by a major Miocene expansion fault. Miocene sands are trapped structurally and stratigraphically 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 300 MMBoe since production first began in 1957. There are 11 major production platforms and 75 smaller structures located throughout the field. During 2005, Marlin drilled a total of five wells in the field, including one replacement well with the proceeds from an insurance claim. Since June 2006 we have drilled ten wells and expect to drill five additional wells in the second half of fiscal year 2007. Average daily production for the quarter ended March 31, 2007 for South Timbalier 21 was 8,342 Boed. South Timbalier 21 accounted for approximately 48% of our net production for the period from July 25, 2005 (inception) to June 30, 2006. As of June 30, 2006 net proved reserves for the field are 15,881 MBoe.

Main Pass 74 Field. The Main Pass 74 field is located in Plaquemines Parish, Louisiana and includes OCS blocks Main Pass 72 and 74. Petroquest Energy, L.L.C. is the operator of the properties and we have a 25% working interest in the field. The field consists of two wells that were drilled in 2003, which recently returned to production after sustaining damage from Hurricane Ivan in September 2004. These gas wells are producing from the Puma Reservoir which has cumulative production of more than 31.5 MMBoe. Net reserves booked as of June 30, 2006 are 869 MBoe.

Rabbit Island Field. Rabbit Island is located in Louisiana state waters (state lease 340) in Iberia and St. Mary Parishes, 95 miles southwest of New Orleans, Louisiana. We operate and have a 99.9% working interest in the field. This field, covering approximately 27,000 acres, was discovered in 1939 by Texaco and has produced over 1.2 Tcf (trillion cubic feet) of natural gas. The field is a structurally complex faulted shallow piercement salt dome with associated radial faulting. To date, there are 53 producing horizons (Pleistocene to Miocene) ranging from 1,600-12,000 feet. We have drilled five successful wells since June 2006. Average daily production for the quarter ended March 31, 2007 for this field was 1,512 Boed. This field has over 8,868 MBoe of net proved reserves.

Manila Village Field. The Manila Village Field is located in Jefferson Parish, Louisiana (state leases 18143 and 18727) approximately 70 miles south of New Orleans, Louisiana. We operate five wells on the west side of the field and have a working interest of 50%. Manila Village Field was discovered in 1965 and has produced in excess of 104 Bcfs and 24 MMBbls from Miocene age sands. Reservoirs are primarily pressure depletion with very little water drive support. Our production comes from the northeast-southwest trending productive sands exhibiting a seismic amplitude anomaly. The reservoirs are characterized by thin bedded laminated sandstones. Average daily production for the quarter ended March 31, 2007 for this field was 924 Boed. Current reserves total 1,540 MBoe net proved.

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Lake Boudreaux Field. Lake Boudreaux is a gas field located onshore South Louisiana in Terrebonne Parish, 65 miles southwest of New Orleans, Louisiana. Apache Corp. is the operator of the field and we have a working interest of 16.25% in five producing wells. The field was discovered in 1971 by Amoco. There have been 26 wells drilled with a cumulative production in excess of 118 Bcf and 1.6 MMBbls. Wells drilled are typically 12,000 to 15,000 feet. Our production is from the Middle Miocene Cib Carstani and Tex W sands. The reservoir is a north dipping high-side fault closure. The five wells had an average daily production for the quarter ended March 31, 2007 of 780 Boed. We have net proved reserves for the field of 1,062 MBoe and two exploration wells have been drilled this year.

Lake Salvador Field and Joint Development Agreement. We have entered into a Joint Development Agreement (JDA) for the Lake Salvador Project with Castex. We and Castex both have a 50% working interest in the JDA. The project covers 1,680 square miles south of New Orleans, Louisiana in an area where fields have produced a total of 1,300 MMBbls and 8.7 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.

Exploration Agreement. In July 2006, we entered into an exclusive 50/50 Exploration Agreement with Castex for twenty-four months covering an Area of Mutual Interest (“AMI”) in South Louisiana. The exploration agreement covers in excess of 1,500,000 acres, and both we and Castex will generate and operate prospects within the AMI. Operatorship will be 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 have 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 fifty percent (50%) interest in seven prospects within the Gridiron Project Area of Mutual Interest (“AMI”) Outline.

We have the option to drill and anticipate drilling six to eight exploratory wells within the Gridiron project over the next twelve months. We will bear 66.67% 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. We will serve as operator of the project and the first well was spud in late February 2007.

South Lake Verret

Energy XXI Gulf Coast, Inc. and Centurion Exploration Company have entered into a Participation Agreement dated January 26, 2007 covering 811 gross and net acres in the South Lake Verret Prospect in St. Martin Parish, LA. Pursuant to the agreement, we paid a consideration of approximately $0.3 million to acquire sixty-six and two thirds percent (66.67%) interest in the prospect.

We will serve as operator and will bear eighty percent (80%) of the costs to drill the initial well. We anticipate that the initial test well will be commenced in June 2007.

Pogo Properties

As part of the Pogo Acquisition, we acquired 28 properties, including:

Main Pass 61 Field. The Main Pass 61 field is 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. The field is company operated with a 50% working interest and about a 40% net revenue interest. There are 15 producing wells and 5 major production platforms located throughout the field. Main Pass 61 was discovered in 2000. The field began producing in 2002 and has since produced 33.9 MMBoe. Average current production for the quarter ended March 31, 2007 for Main Pass 61 is 3,163 Boed net. Reserves for Main Pass 61 as of December 31, 2006 totaled 8.5 MMBoe net.

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Main Pass 72 Field. The Main Pass 72 field is located in approximately 100 feet of water near the mouth of the Mississippi River and is in close proximity to Main Pass 61 Field. This field consists of OCS blocks Main Pass 72, 73, and 74. Since discovery in 1980, this field has produced 95.7 MMBoe. Main Pass 72 is company operated with a 50% working interest and a 41.67% net revenue interest. 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. Reserves as of December 31, 2006 totaled 3.0 MMBoe net and current average production for the quarter ended March 31, 2007 is 148 Boed net.

South Pass 49 Field. The South Pass 49 field is located near the mouth of the Mississippi River in approximately 300 feet of water. The field consists of OCS blocks South Pass 33, 48, and 49. South Pass 49 field is company operated with Energy XXI having a 33.3% working interest in the unit and a 10% working interest in the non unit. The Company’s net revenue interest in the unit is 27.8% and in the non unit is 8.4 %. The unit consists of the D69 and D70 sands which are the primary producing horizons in the field. Non unit production comes from 12 additional sands ranging in depth from 7,200 to 9,000 feet. South Pass 49 field has produced 102 MMBoe. Production for South Pass 49 for the quarter ended March 31, 2007 is 555 Boed net and reserves as of December 31, 2006 totaled 1.2 MMBoe net.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to undeveloped acreage in farm-out agreements and oil and gas leases. Prior to the commencement of drilling operations, we conduct a thorough title examination and perform curative work with respect to significant defects. We have obtained title opinions on substantially all of our producing properties, including all of the properties listed above as our top five producing assets, and believe that we have satisfactory title to these properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and gas leases, we obtain title opinions on the most significant leases.

Offices

Our registered office is Canon’s Court, 22 Victoria Street, PO Box HM 1179, Hamilton HM EX, Bermuda and our principal subsidiary has its offices at 1021 Main, Suite 2626, Houston, Texas 77002.

Our lease agreement for our Houston offices terminates on July 31, 2013. Future annual minimum lease commitments under the agreement at March 31, 2007 are $728,000, $728,000, $728,000, $728,000, $728,000 and $976,000 in 2007, 2008, 2009, 2010, 2011 and thereafter, respectively.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth as of June 21, 2007 the number and percentage of the outstanding shares of our common stock, which according to the information available to us, were beneficially owned by each person who beneficially owns 5% or more of the outstanding common stock and by all of our directors and executive officers, individually and as a group.

Name and Address of Beneficial Owner	Number of Common Shares			Percent of Class
Windmill Master Fund 2579 Washington Road—Suite 322 Pittsburgh, Pennsylvania 15241		14,600,001(1	)		15.98	%
Seneca Capital International Ltd. 590 Madison Avenue—28th Floor New York, New York 10022		11,520,203(2	)		12.63	%
Satellite Overseas Fund Ltd. c/o Morstan Nominees Limited 25 Cabot Square, Canary Wharf, London E14 4QW		9,764,587(3	)		10.76	%
Nathan Low 641 Lexington Ave., 25th Floor New York, NY 10022		9,869,079(4	)		10.51	%
Nisswa Master Fund Ltd. 800 Nicollet Mall, Suite 2850 Minneapolis, MN 55402		8,253,500(5	)		8.9	%
The Ospraie Portfolio LTD 320 Park Ave., 27th Floor New York, NY 10022		6,071,668(6	)		7.05	%
Artemis UK Small Companies Fund c/o HSBC Global Custody Nominee (UK) Limited 981685 Acct Mariner House, Pepys Street London EC3N 4DA		4,999,998			5.95	%
Sunrise Equity Partners, L.P. 641 Lexington Ave., 25th Floor New York, NY 10022		5,000,001(7	)		5.75	%
Majedie Asset Management Ltd. One Canary Lane, London EC2V 8AE		4,424,999			5.26	%
John D. Schiller, Jr. (8)(9)(10)(11)		9,454,201			10.89	%
Steven A. Weyel (9)(10)(11)		2,995,000			3.55	%
David West Griffin (9)(10)(11)(12)		1,435,201			1.71	%
Stewart Lawrence		20,100			*
William Colvin		67,632			*
Paul Davison		3,000			*
David M. Dunwoody		45,339			*
Hill A. Feinberg		253,000			*
Ben Marchive (13)		112,500			*
Steve Nelson (13)		55,000			*
All directors and officers as a group (10 persons as of June 21, 2007)		14,440,973			16.51%

* Indicates less than 1%

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(1) Includes 7,300,000 common shares underlying warrants.

(2) Includes 7,125,802 common shares underlying warrants.

(3) Includes 6,125,105 common shares underlying warrants.

(4) Includes 3,675,303 common shares underlying warrants and 6,193,776 common shares underlying 2,064,592 unit purchase options. Each unit purchase option is exercisable into one common share and two warrants, and each of the two warrants are then exercisable into one common stock. Does not include (i) 20,000 common shares and 500,001 common shares underlying 166,667 unit purchase options owned by Sunrise Securities Corp. (“SSC”), (ii) 2,059,167 shares of common stock and 2,940,834 common shares underlying warrants owned by Sunrise Equity Partners, L.P. (“SEP”) and (iii) 1,548,444 common shares underlying 516,148 unit purchase options owned by SFT. Mr. Nathan Low disclaims beneficial ownership of all of our securities owned by the Sunrise Foundation Trust (“SFT”) and Sunrise Equity Partners, L.P. (“SEP”) (other than Mr. Nathan Low’s ownership of our securities as a result of his ownership of limited partnership interests of SEP).

(5) Includes 7,728,500 common shares underlying warrants.

(6) Includes 2,416,668 common shares underlying warrants.

(7) Includes 2,940,834 common shares underlying warrants.

(8) Includes 150,000 shares Mr. Schiller has transferred to individual family members and 500,000 shares held in trust for the benefit of his family. Mr. Schiller maintains voting control of the shares so transferred but otherwise disclaims beneficial ownership.

(9) Includes 87,500 shares with respect to Mr. Schiller, 11,667 shares with respect to Mr. Weyel, 5,833 shares with respect to Mr. Griffin by virtue of their respective 75%, 10% and 5% ownership of The Exploitation Company, LLP, a limited liability partnership, which we refer to herein as TEC, and owner of 116,667 shares.

(10) Includes 562,500 shares with respect to Mr. Schiller, 350,000 shares with respect to Mr. Weyel, 337,500 shares with respect to Mr. Griffin by virtue of their respective 45%, 28% and 27% ownership of Energy XXI Partners, a limited liability corporation partnership, and owner of 1,250,000 shares.

(11) Includes common stock underlying warrants of 2,725,001, 383,333 and 261,080 with respect to Mr. Schiller, Mr. Weyel and Mr. Griffin, respectively.

(12) Includes 200 shares owned by Mr. Griffin’s family members. Mr. Griffin maintains voting control of the shares.

(13) As part of their employment in April 2006, Mr. Marchive and Mr. Nelson were granted a combination of restricted shares and restricted share units, which vest one-third each year beginning on April 10, 2007 and April 17, 2007, respectively. These amounts include 62,500 and 55,000 of the restricted share portion of the grant for Mr. Marchive and Mr. Nelson, respectively. The allocation of the total grant between restricted stock and restricted stock units was approved by our Board of Directors in October 2006.

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DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth the names, ages, and positions of each of our directors and 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
William Colvin	48	Director	July 2005
Paul Davison	54	Director	May 2007
David M. Dunwoody	57	Director	July 2005
Hill A. Feinberg	60	Director	May 2007
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

Our Board of Directors is divided into three classes, Class I, Class II and Class III with staggered terms of office ending in 2009, 2007 and 2008, respectively. The term for each class expires on the date of the third annual general meeting following the most recent election of directors for such class. Each director holds office until the next annual general meeting for the election of directors of his class and until his successor has been duly elected and qualified. Currently our Class I directors are Hill A. Feinberg and David West Griffin, our Class II directors are Steven A. Weyel, Paul Davison and David M. Dunwoody and our Class III directors are John D. Schiller, Jr. and William Colvin. All officers serve at the discretion of the Board of Directors. The following is information on the business experience of each director and officer.

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 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. Mr. Schiller is a member of our nominating committee.

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 serves with Mr. Schiller on the Board of Directors of Particle Drilling. 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.

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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.

William Colvin. Mr. Colvin is one of our independent non-executive directors. He chairs both the audit and nomination committees and is a member of its remuneration committee. Mr. Colvin was appointed chairman of the board of Southern Cross Healthcare PLC, a nursing home operator based in the UK, in March 2005 following the acquisition of NHP plc by funds controlled by The Blackstone Group. From January 2000 to February 2005 Mr. Colvin was a director of NHP Plc, a property investment group in the UK specializing in the ownership of freehold or long leasehold interests in modern purpose-built nursing homes. From November 2000 to February 2005, Mr. Colvin was also the Chief Executive of NHP Plc. He was Finance Director of British-Borneo Oil & Gas Plc from 1992 to 1999. From 1990 to 1992, Mr. Colvin was Finance Manager/Director at Oryx UK Energy. From 1989 to 1990, he was group financial controller at Thames Television plc. From 1984 to 1989, he worked in a variety of financial roles for Atlantic Richfield (ARCO) Inc. From 1979 to 1984, Mr. Colvin worked in the audit department of Ernst & Young. He is also a non-executive director of Sondex Plc and BSN Medical. He qualified as a Scottish Chartered Accountant in 1982 and holds a Bachelor of Commerce degree from the University of Edinburgh.

Paul Davison. Mr. Davison is one of our independent non-executive directors. He became a director on May 7, 2007 and is a member of our audit, nomination and remuneration committees. Mr. Davison has over 30 years of experience in the oil and gas industry, mostly recently serving as Executive Director and later as the Technical and Operations Director of Paladin Resources plc from 1997 until its takeover in 2006. Since 2006 he has pursed personal interests. Mr. Davison graduated from Nottingham University in 1974 with a degree in Mining Engineering.

David M. Dunwoody. Mr. Dunwoody is one of our independent non-executive directors. He chairs the remuneration committee and is a member of its audit and nomination committees. Mr. Dunwoody is the President of Morris Pipeline Company, a natural gas gathering company operating in Texas and has served in that capacity since 1998. From 1982 to 1998, Mr. Dunwoody held various positions with TECO Pipeline Company, an intrastate pipeline company operating in Texas. Prior to being acquired by PG&E Corporation, TECO operated over 1,100 miles of gas gathering and transmission pipelines. Mr. Dunwoody graduated from the University of Texas at Austin in 1971, receiving a Bachelors of Business Administration degree.

Hill A. Feinberg. Mr. Feinberg is one of our independent non-executive directors. He became a director on May 7, 2007 and is a member of our audit, nomination and remuneration committees. Mr. Feinberg is Chairman and Chief Executive Officer of First Southwest Company, a privately held, fully diversified investment banking firm for which he has worked since 1991. He is active in numerous industry, civic and charitable organizations. Mr. Feinberg is a member of the board of the Cardiopulmonary Research Science and Technology Institute, the Board of Visitors for UT Southwestern Medical Center, Texas Regional Bancshares and the Greater Dallas Chamber. Mr. Feinberg graduated from the University of Georgia in 1969 with a bachelor’s degree in finance.

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, one of the nation’s largest independent oil and gas exploration and production companies. From 1996 to 2001, Mr. Lawrence was responsible for investor relations, media relations, shareholder services 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 in 1987 and received his Masters in Business Administration from the University of Houston in 1995.

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Hugh A. Menown. Mr. Menown is our Vice President and Chief Accounting Officer. He has more than 26 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 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 following 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.

Executive board members receive no compensation for their board duties. Non-executive board members have received 25,000 shares of our common stock and as approved by the board in October 2006, receive a $30,000 annual retainer, payable quarterly, 6,000 shares of restricted stock awarded annually which vest on the one-year anniversary of the award, $15,000 annual retainer, payable quarterly to the chairman of the audit committee, $10,000 annual retainer, payable quarterly to the chairman of any committee other than the audit committee, $2,500 for each board meeting attended and $1,500 for each committee meeting attended, plus reimbursement of all out-of-pocket expenses associated with the performance of their board duties. To extent the board members elect to forego cash compensation, they receive stock with a market value equal to 150% of the cash equivalent of the cash compensation they forego.

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EXECUTIVE COMPENSATION

The following table sets forth certain information regarding the annual and long-term compensation for services in all capacities to us for the year ended June 30, 2006 of those persons who were our executive officers for the year ended June 30, 2006, and who receive annual salary and bonuses exceeding $100,000.

	Annual Compensation								Long Term Compensation
Name and	Annual		Salary through June 30,				Other Annual Compensation		Other Compensation through June 30,		Restricted Stock Award(s) (3) (4)				Restricted Stock Unit Award(s) (3) (4)
Principal Position	Salary ($)		2006		Bonus (1)		(2)		2006 (2)		Shares		($)		Shares		($)
John D. Schiller, Jr.   Chairman of the Board and Chief Executive Officer	$	475,000	$	118,750		—	$	97,000	$	21,723		—		—		—		—
Steven A. Weyel President, Chief Operating Officer and Director	$	395,000	$	98,750		—	$	81,200	$	18,198		—		—		—		—
David West Griffin Chief Financial Officer	$	260,000	$	65,000		—	$	56,600	$	12,850		—		—		—		—
Ben Marchive Senior Vice President, Operations	$	225,000	$	51,202		—	$	51,000	$	32,995		62,500	$	329,375		62,500	$	329,375
Steve Nelson Vice President of Drilling and Production	$	200,000	$	41,667		—	$	44,000	$	28,667		55,000	$	289,850		55,000	$	289,850

(1) No bonuses have been paid as of June 30, 2006. In October 2006, the Board of Directors authorized bonuses of $712,500, $444,375 and $104,500 to Mr. Schiller, Mr. Weyel and Mr. Griffin, respectively. These bonuses related to the employee’s performance subsequent to June 30, 2006 including the successful completion of the Castex acquisition.

(2) Included in “Other Annual Compensation” and “Other Compensation through June 30, 2006” are Profit Sharing Plan (10%) of employee salary (excluding any bonus awards), car allowances (ranging from $1,000 to $1,750 per month) and 401(k) matching, assuming a 6% match of the employee’s regular earnings (excluding any bonus awards). We plan on putting in place a non-qualified plan to enable employees to make additional contributions in excess of the maximum contributions allowed under the 401(k) rules. Included in “Other Compensation through June 30, 2006” are signing bonuses paid to Mr. Marchive and Mr. Nelson as a condition of their employment.

(3) Shares valued at June 2006 monthly average of $5.27 and vest over a three year period from the anniversary of the individual’s start date.

(4) As part of their employment in April 2006, Mr. Marchive and Mr. Nelson received a total grant of 125,000 and 110,000, respectively, of restricted stock and or restricted stock units, which vest one-third each year over a three year period. The allocation of the total grant between restricted stock and restricted stock units was approved by our Board of Directors in October 2006.

Stock Options

We have never granted stock options to our executive officers and directors and no stock options currently exist with respect to our common stock. However, as noted below, under our 2006 Long-Term Incentive Plan our board of directors may grant stock options to our executive officers in the future.

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Restricted Stock and Warrants

The chairman, the president and the chief financial officer purchased stock in the company at the time of its formation in July 2005. As part of the offering of stock and warrants on October 20, 2005, each of these individuals signed agreements restricting the sale of their stock until October 20, 2008. In addition, these individuals and partnerships controlled by these individuals purchased shares during the initial public offering on the AIM on October 20, 2005 as well as certain warrants purchased immediately after the listing on the open market. The table below shows the beneficial ownership of each individual and the timing of the removal of the restriction on the stock and warrants.

	Shares
Name	Short-Term Restricted (1)		Restricted/ Vested (2)
John D. Schiller, Jr.		187,500		6,541,700(3	)
Steven A. Weyel		61,667		2,550,000
David West Griffin		86,421		1,087,500

(1) Short-term restricted stock became unrestricted on April 4, 2007.

(2) Restricted/Vested Shares subject to lock expiring on October 20, 2008.

(3) Includes 650,000 shares owned by Mr. Schiller’s family members.

As of June 19, 2007, the following warrants were held by the officers and directors listed below:

Warrants/Options Held by Officers (1)

Name	# of Warrants Held
John D. Schiller, Jr.		2,725,001
Steven A. Weyel		383,333
David West Griffin		261,080

(1) Includes 2,125,001 warrants with respect to Mr. Schiller, 283,333 warrants with respect to Mr. Weyel, 141,667 warrants with respect to Mr. Griffin by virtue of their respective 75%, 10% and 5% ownership of The Exploitation Company, a limited liability partnership, and owner of 2,833,334 warrants.

2006 Long-Term Incentive Plan

Our 2006 Long-Term Incentive Plan enables the compensation committee of the board to award restricted stock, restricted stock units, stock appreciation rights, performance awards and options to any of our employees. A total of 1,250,000 shares have been reserved for issuance under this plan. As of June 19, 2007, we had issued a total of 117,500 shares of restricted stock and 1,703,700 restricted stock units under the plan to certain employees as a component of their compensation package. No other awards have been issued under this plan. The restricted stock issued vests over a three-year period with equal vesting. The restricted stock units are issued from time to time at a value equal to our stock price at the time of issue. The restricted stock units vest over a three-year period with equal vesting each year. When vesting occurs, we pay the employee an amount equal to the then current our stock price times the number of restricted stock units that have vested. At our sole discretion at the time the restricted stock units vest, we have the ability to offer the employee to accept shares in lieu of cash. The restricted stock units cease to vest upon termination of employment.

We recognize as an accrual the time that the employees have held the restricted stock or restricted stock unit relative to the vesting period times the change in our stock price. Upon a change in control, all outstanding restricted stock and restricted stock units become immediately exercisable.

Profit Sharing Program

We have an employee profit sharing program which pays up to 10% of their base salary to the employees’ personal retirement account. Subsequent to June 30, 2006, we approved and paid a total of $74,561 to the employees retirement accounts in accordance with the plan for the period ending June 30, 2006. Expenses under the profit sharing plan for the nine months ended March 31, 2007 were $502,840.

Compensation Arrangements

On April 4, 2006, we entered into employment agreements with each of Messrs. Schiller, Weyel, and Griffin, who serve as our Chief Executive Officer and Chairman of its Board of Directors, President and Chief Operating Officer, and Chief Financial Officer, respectively. The following is a summary of the material provisions of the forms of those employment agreements.

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The employment agreements provide for an annual base salary of $475,000 for Mr. Schiller, $395,000 for Mr. Weyel, and $260,000 for Mr. Griffin. In addition, subject to the satisfaction of performance criteria established by the Board of Directors or the remuneration committee of the Board, each of Messrs. Schiller, Weyel and Griffin will have the opportunity to receive an annual target incentive bonus under the terms of an incentive compensation plan approved by the Board or the remuneration committee equal to the following target amounts of each executive’s annual base salary: 100% for Mr. Schiller, 75% for Mr. Weyel, and 55% for Mr. Griffin. During the period of employment 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 our other executive employees from time to time.

Each employment agreement has an initial term beginning on April 4, 2006 and ending on October 20, 2008, but the term of the agreement will automatically be 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. Either party may also terminate the executive’s employment under the agreement at any time for any reason, provided that we may not terminate an executive’s employment without cause during the four-month period beginning with the effective date of the employment agreement. If an executive’s employment is subject to an “involuntarily termination” (which term means any termination which does not result from a resignation by the executive (except where the executive resigns within 60 days of a material change to the executive’s duties, remuneration or terms), but does not include termination for cause or due to the executive’s death or disability), then the executive will be entitled to (i) severance in a lump sum payment equal to (a) the sum of the executive’s annual base salary and average annual incentive bonuses earned over a period specified in the employment agreement multiplied by (b) a fraction, the numerator of which is the number of full and partial months in the period beginning on the date of such termination and ending on the last day of the then remaining term of the agreement (but in no event less than 12), and the denominator of which is 12, and (ii) continued participation for up to three years in our medical, dental and life insurance programs (or equivalent programs) at no greater cost to the executive than that applicable to him immediately prior to such termination of employment. Further, if such involuntary termination occurs during a “change of control period” (which means the period beginning 90 days prior to the date on which a definitive agreement relating to a change of control of is executed and ending on the date one year after the date on which the change of control occurs) or if the executive’s employment is terminated due to his death or disability, then any outstanding options to purchase common shares will become immediately exercisable and any restricted common shares, as well as executive’s accrued benefits under any nonqualified deferred compensation plans sponsored by us, will become immediately nonforfeitable.

“Change of control” for these purposes means (i) a merger or consolidation involving us, (ii) a sale of all or substantially all of our assets, (iii) our dissolution or liquidation, (iv) where any person (including a group of persons acting together) acquires or gains ownership or control of more than 50% of the voting rights attaching to our securities, or (v) where, in connection with a contested election of the directors, the persons who were members of the Board of Directors immediately prior to such election cease to constitute a majority of the Board of Directors. Each employment agreement also provides that if any payment received by an executive is subject to the federal excise tax under Section 4999 of the Internal Revenue Code, the payment will be grossed up to permit the executive to retain a net amount on an after-tax basis equal to what he would have received had the excise tax (including any interest or penalties) on such payment not been payable.

We have entered into non-executive appointment letters dated August 31, 2005 with William (Bill) Colvin and David M. Dunwoody, pursuant to which Mr. Colvin and Mr. Dunwoody agreed to act as non-executive directors of Energy XXI for a period of three years. The term of service may also be terminated by either party on one month’s written notice. During the period ended June 30, 2006, each of Mr. Colvin and Mr. Dunwoody has received 25,000 common shares by way of compensation for their services plus reimbursement for all reasonable out of pocket expenses incurred by them in the performance of their services to us. In October 2006, the Board of Directors adopted a non-executive director remuneration plan which provides for a $30,000 annual retainer, payable quarterly, 6,000 shares of restricted stock awarded annually and vesting on the one-year anniversary of the award, $15,000 annual retainer, payable quarterly to the chairman of the audit committee, $10,000 annual retainer, payable quarterly to the chairman of any committee other than the audit committee, $2,500 for each board meeting attended and $1,500 for each committee meeting attended. To the extent the board members elect to forego cash compensation, they receive stock with a market value equal to 150% of the cash equivalent of the cash compensation they forego. We have also entered into non-executive appointment letters dated April 16, 2007 and April 24, 2007 with Hill Feinberg and Paul Davison, respectively, pursuant to which Mr. Feinberg and Mr. Davison agreed to act as non-executive directors of Energy XXI for a period of two years, subject to election at the 2007 annual meeting. Mr. Feinberg and Mr. Davison, each are compensated pursuant to the non-executive director remuneration plan adopted by the Board of Directors in October 2006 as described above.

We have put in place directors’ and officers’ liability insurance policies to cover all of our directors.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

We assumed certain contracts and obligations relating to our initial public offering and organization costs that were entered into and paid, prior to our formation, by TEC, a partnership controlled by Messrs. Schiller, Weyel and Griffin. In addition, as a convenience to us, TEC also paid for certain of our expenses, including offering expenses, for which we subsequently reimbursed TEC. TEC charged no fees or interest for this service.

Furthermore, from October 20, 2005 through 2006 we paid a total of $7,500 per month to TEC, to rent office space and to pay staff expenses. These expenses totalled $37,500 for the period from October 20, 2005 through March 31, 2006. We incurred no further expenses for these services subsequent to March 31, 2006. The amounts paid to TEC were equal to or less than TEC’s actual expenses associated with providing these services.

There have been no other transactions or business relationships between any director, executive officer, 5% holder or family member and us nor is there any indebtedness owed to us by these individuals.

LEGAL PROCEEDINGS

We are a defendant 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.

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MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S COMMON EQUITY

AND RELATED STOCKHOLDER MATTERS

Our restricted common stock and warrants trade on the AIM Exchange under the symbol “EXXS” and “EGYW”. 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”. Our restricted common stock will continue to trade under the symbol “EXXS”. On June 1, 2007, we commenced trading on the United States OTCBB under the symbol “EXXIF.OB”. Since trading commenced, the high and low sale prices on the OTCBB have been $6.44 and $5.25, respectively. The following table sets forth the high and low sale prices per share of the restricted and unrestricted common stock and warrants as reported for the periods indicated.  

		High						Low
Quarter Ended		Restricted Common Stock		Unrestricted Common Stock		Warrants		Restricted Common Stock		Unrestricted Common Stock		Warrants
December 31, 2005 (began trading October 20, 2005)	$	5.35		—	$	0.56	$	5.12		—	$	0.54
March 31, 2006	$	5.95		—	$	0.98	$	5.24		—	$	0.57
June 30, 2006	$	5.62		—	$	1.17	$	5.15		—	$	1.00
September 30, 2006	$	5.15		—	$	1.14	$	4.95		—	$	0.96
December 31, 2006	$	5.15		—	$	0.96	$	4.87		—	$	0.84
March 31, 2007	$	4.96		—	$	0.93	$	4.65		—	$	0.63
June 30, 2007 (through June 19, 2007)	$	6.05	$	6.44	$	1.58	$	4.78	$	5.25	$	0.63

As of June 19, 2007, there were approximately 428 holders of common stock and 97 holders of warrants. We have never paid dividends on our common stock and intend to retain our cash flow from operations, 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.

DESCRIPTION OF REGISTRANT’S SECURITIES TO BE REGISTERED

We are authorized to issue up to 400,000,000 shares of our common stock, par value $0.001. As of June 19, 2007, there were 84,072,699 shares of common stock issued and outstanding. The holders of common stock are entitled to one vote per share on each matter submitted to a vote of stockholders. In the event of liquidation, holders of common stock are entitled to share ratably in the distribution of assets remaining after payment of liabilities, if any. Holders of common stock have no cumulative voting rights, and, accordingly, the holders of a majority of the outstanding shares have the ability to elect all of the directors. Holders of common stock have no preemptive or other rights to subscribe for shares. Holders of common stock are entitled to such dividends as may be declared by the board of directors out of funds legally available. The outstanding common stock is validly issued, fully paid and non-assessable.

We are also authorized to issue up to 2,500,000 preference shares, par value $0.001. No preference shares have been issued. If preference shares are issued, they may be subject to redemption by the company upon certain events or on given dates as set forth in resolutions of the Board of Directors authorizing the issuance of such preference shares. Such shares may also have such preferred dividend, voting, return of capital or the rights as the Board of Directors may determine. As a result, the Board of Directors could authorize the issuance of preferred shares with terms and conditions that could have the effect of delaying, deferring or preventing a change in control of the company.

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PLAN OF DISTRIBUTION

We are registering the shares of common stock previously issued and the shares of common stock issuable upon exercise of the warrants to permit the resale of these shares of common stock by the holders of the common stock and warrants from time to time after the date of this prospectus. We will not receive any of the proceeds from the sale by the selling stockholders of the shares of common stock. However, we will receive the sale price of any common stock we sell to the selling stockholders upon exercise of the warrants and we will receive the sale price of any exercised unit purchase option. We will bear all fees and expenses incident to our obligation to register the shares of common stock.

The selling stockholders and any of their pledgees, donees, transferees, assignees and successors-in-interest may, from time to time, sell any or all of their shares of common stock on any stock exchange, market or trading facility on which the shares are traded or in private transactions. These sales may be at fixed prices, at prevailing market prices at the time of sale, at varying prices determined at the time of sale or negotiated prices. The selling stockholders may use any one or more of the following methods when selling shares:

· ordinary brokerage transactions and transactions in which the broker-dealer solicits investors;

· block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

· purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

· an exchange distribution in accordance with the rules of the applicable exchange;

· privately negotiated transactions;

· to cover short sales made after the date that this registration statement is declared effective by the SEC;

· through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;

· broker-dealers may agree with the selling stockholders to sell a specified number of such shares at a stipulated price per share;

· a combination of any such methods of sale; and

· any other method permitted pursuant to applicable law.

The selling stockholders may also sell shares under Rule 144 under the Securities Act, if available, rather than under this prospectus.

Broker-dealers engaged by the selling stockholders may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the selling stockholders (or, if any broker-dealer acts as agent for the purchaser of shares, from the purchaser) in amounts to be negotiated. The selling stockholders do not expect these commissions and discounts to exceed what is customary in the types of transactions involved.

The selling stockholders may from time to time pledge or grant a security interest in some or all of the shares owned by them and, if they default in the performance of their secured obligations, the pledgees or secured parties may offer and sell shares of common stock from time to time under this prospectus, or under an amendment to this prospectus under Rule 424(b)(3) or other applicable provision of the Securities Act of 1933 amending the list of selling stockholders to include the pledgee, transferee or other successors in interest as selling stockholders under this prospectus. In connection with the sale of our common stock or interests therein, the selling stockholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of the common stock in the course of hedging the positions they assume. The selling stockholders may also sell shares of our common stock short and if such short sale shall take place after the date that this registration statement is declared effective by the SEC, the selling stockholders may deliver these securities to close out such short sales, or loan or pledge the common stock to broker-dealers that in turn may sell these securities. The selling stockholders may also enter into option or other transactions with broker-dealers or other financial institutions or the creation of one or more derivative securities which require the delivery to such broker-dealer or other financial institution of shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).

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Upon us being notified in writing by a selling stockholder that any material arrangement has been entered into with a broker-dealer for the sale of common stock through a block trade, special offering, exchange distribution or secondary distribution or a purchase by a broker or dealer, a supplement to this prospectus will be filed, if required, pursuant to Rule 424(b) under the Securities Act, disclosing (i) the name of each such selling stockholder and of the participating broker-dealer(s), (ii) the number of shares involved, (iii) the price at which such the shares of common stock were sold, (iv) the commissions paid or discounts or concessions allowed to such broker-dealer(s), where applicable, (v) that such broker-dealer(s) did not conduct any investigation to verify the information set out or incorporated by reference in this prospectus, and (vi) other facts material to the transaction. In addition, upon us being notified in writing by a selling stockholder that a donee or pledgee intends to sell more than 500 shares of common stock, a supplement to this prospectus will be filed if then required in accordance with applicable securities law.

The selling stockholders also may transfer the shares of common stock in other circumstances, in which case the transferees, pledgees or other successors in interest will be the selling beneficial owners for purposes of this prospectus.

The selling stockholders and any broker-dealers or agents that are involved in selling the shares may be deemed to be “underwriters” within the meaning of the Securities Act in connection with such sales. If a selling stockholder is deemed to be an underwriter, the selling stockholder may be subject to certain statutory liabilities including, but not limited to Section 11, 12 and 17 of the Securities Act and Rule 10b-5 under the Exchange Act. If a selling stockholder is deemed to be an underwriter, any commissions received by such broker-dealers or agents and any profit on the resale of the shares purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act. Discounts, concessions, commissions and similar selling expenses, if any, that can be attributed to the sale of securities will be paid by the selling stockholder and/or the purchasers.

If a selling stockholder uses this prospectus for any sale of the common stock, it will be subject to the prospectus delivery requirements of the Securities Act unless an exemption therefrom is available.

The selling stockholders will be responsible to comply with the applicable provisions of the Securities Act and Exchange Act, and the rules and regulations thereunder promulgated, including, without limitation, Regulation M, as applicable to such selling stockholders in connection with resales of their respective shares under this registration statement.

Under the securities laws of some states, the shares of common stock may be sold in such states only through registered or licensed brokers or dealers.

In addition, in some states the shares of common stock may not be sold unless such shares have been registered or qualified for sale in such state or an exemption from registration or qualification is available and is complied with.

There can be no assurance that any selling stockholder will sell any or all of the shares of common stock registered pursuant to the registration statement, of which this prospectus forms a part. Once sold under the registration statement, of which this prospectus forms a part, the shares of common stock will be freely tradable in the hands of persons other than our affiliates.

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SELLING STOCKHOLDERS

The table below sets forth information concerning the resale of the shares of common stock by the selling stockholders. Unless otherwise indicated below, each of the selling stockholders acquired its common units, warrants and unit purchase options in connection with our initial public offering on the “Alternate Investment Market” of the London Stock Exchange in October 2005. We will not receive any proceeds from the resale of the common stock by the selling stockholders. We will receive proceeds from the exercise of the warrants, but not on the sale of the common stock issued to the selling stockholder upon exercise of the warrants. Assuming all the shares registered below are sold by the selling stockholders, none of the selling stockholders will continue to own any shares of our common stock registered pursuant to the registration statement of which this prospectus forms a part.

The following table also sets forth the name of each person who is offering the resale of shares of common stock by this prospectus, the number of shares of common stock beneficially owned by each person based on its ownership of the shares of common stock and the warrants, as of June 19, 2007, assuming exercise of the warrants held by the selling stockholders on that date, without regard to any limitations on exercise, the number of shares of common stock that may be sold in this offering and the number of shares of common stock each person will own after the offering, assuming they sell all of the shares offered.

Unless otherwise indicated below, none of the selling stockholders have and within the past three years had any position, office or other material relationship with us or any of our predecessors or affiliates. In addition, based on information furnished by the selling stockholders, none of the selling stockholders are broker-dealers, affiliates of broker-dealers or underwriters, except as noted in the footnotes below.

	Beneficial Ownership Prior to the Offering (1)
Name of Selling Stockholder	Shares			Percentage (2)			Shares Offered
Eric Abitbol		85,681	(51)		*			85,681(51	)
Aim Realisation Fund Limited (3)		1,200,000	(3)		1.4	%		1,200,000(3	)
AHFP Context (4)		12,138	(52)		*			12,138(52	)
Alpha Capital Austalt (5)		250,002	(53)		*			250,002(53	)
Altma Fund Sicav Plc in Respect of the Grafton Sub Fund (4)		60,075	(54)		*			60,075(54	)
Anglian Commodities Fund Limited (6)		900,000			1.1	%		900,000
Arbor Partners, L.P. (7)		44,600	(55)		*			44,600(55	)
Eric Richard Bauer		1,100			*			1,100
Ben P. Bono		780			*			780
Casam Context Offshore Advantage Fund Limited (4)		46,950	(56)		*			46,950(56	)
CCM Master Qualified Fund, Ltd. (8)		2,500,002			3.0	%		2,500,002
Simon Nicholas Champ		42,000	(57)		*			42,000(57	)
Cohanzick Credit Opportunities Master Fund, Ltd. (9)		400,000			*			400,000
Context Advantage Master Fund, L.P. (4)		207,596	(58)		*			207,596(58	)
Context Opportunistic Master Fund, L.P. (4)		93,125	(59)		*			93,125(59	)
Cornelius Dupre II		625,000			*			625,000
CRT Capital Group LLC (10)		10,000			*			10,000
Paul Davison		3,000			*			3,000
DKR Soundshore Oasis Holding Fund Ltd. (11)		300,000	(48)		*			300,000(48	)
David M. Dunwoody		45,339			*			45,339
Epic Capital Offshore Inc. (12)		25,000			*			25,000
Epic North American Diversified Fund LP (12)		8,334			*			8,334
Finch Tactical Plus Class B (4)		8,688	(60)		*			8,688(60	)
First New York Securities LLC (13)		90,000			*			90,000
Robert Fuchs		367,500	(61)		*			367,500(61	)
John L. Gallagher		52,500	(62)		*			52,500(62	)
Global Energy & Natural Resources (14)		90,000			*			90,000
Sheldon M. Goldman (15)		1,290,167	(15)		1.5	%		1,290,167(15	)
David Goodfriend (16)		358,755	(16)		*			358,755(16	)
Goldman Sachs Europe Small Cap Portfolio (17)		1,269,934	(63)		1.5	%		1,269,934(63	)
Gracie Capital International, LTD. (18)		1,072,500	(64)		1.3	%		1,072,500(64	)
Gracie Capital International II, LTD. (18)		305,250	(65)		*			305,250(65	)
Gracie Capital LP (19)		1,285,167	(66)		1.5	%		1,285,167(66	)

54

	Beneficial Ownership Prior to the Offering (1)
Name of Selling Stockholder	Shares	Percentage (2)	Shares Offered

Gracie Capital LP II (18)	87,083	(67)			87,083(67	)
David West Griffin	1,439,368	(68)	1.7	%	1,439,368(68	)
David Gwilym Colin Gronow	15,000	(69)	*		15,000(69	)
Guggenheim Portfolio Company VII, LLC (20)	415,000	(70)	*		415,000(70	)
Guggenheim Portfolio Company XII, LLC (21)	525,898	(71)	*		525,898(71	)
Yehuda Harats	192,585	(72)	*		192,585(72	)
Harbor Drive Master Fund, Ltd. (22)	1,325,000	(73)	1.6	%	1,325,000(73	)
Institutional Benchmarks Series (Master Feeder) Limited in Respect of Alcor Series (4)	11,063	(74)	*		11,063(74	)
Iron City Fund, Ltd. (23)	411,099	(75)	*		411,099(75	)
J. Sainsbury Common Investment Fund Limited (17)	647,786	(76)	*		647,786(76	)
JGB Capital L.P. (24)	125,000		*		125,000
JMG Capital Partners, LP (25)	2,723,500	(77)	3.2	%	2,723,500(77	)
JMG Triton Offshore Fund, Ltd. (26)	2,723,500	(78)	3.2	%	2,723,500(78	)
JVL Global Energy, (QP), LP (27)	256,002	(79)	*		256,002(79	)
JVL Global Energy, LP (27)	144,000	(80)	*		144,000(80	)
Marcia Kucher	30,000	(81)	*		30,000(81	)
Stewart Lawrence	20,100		*		20,100
Nathan Low	9,869,079	(82)	10.6	%	9,869,079(82	)
Ruth Low	791,001	(83)	*		791,001(83	)
Lyxor / Context Fund, Ltd. (4)	69,644	(84)	*		69,644(84	)
Amnon Mandelbaum	3,228,804	(85)	3.7	%	3,228,804(85	)
Hugh Allen Menown	36,050		*		36,050
Serge Moyal (28)	24,501	(28)	*		24,501(28	)
National Financial Services LLC (29)	1,000		*		1,000
Navitas Fund, LP (27)	99,999	(86)	*		99,999(86	)
Nisswa Master Fund LTD. (30)	8,253,500	(87)	8.9	%	8,253,500(87	)
Nite Capital LP (31)	100,000	(88)	*		100,000(88	)
Richard Victor Evenett Noble	350		*		350
Novator Credit Opportunities Master Fund (32)	725,000	(89)	*		725,000(89	)
One East Duration Master, LP (33)	438,000		*		438,000
OPK, L.L.C.	625,000	(90)	*		625,000(90	)
Osmium Special Situation Fund (91)	500,000		*		500,000
Portside Growth and Opportunity Fund (34)	500,000		*		500,000
Radcliffe SPC, Ltd., for and on behalf of the Class A Convertible Crossover Segregated Portfolio (35)	700,000	(92)	*		700,000(92	)
Ramius Securities, L.L.C. (36)	962,500	(93)	1.1	%	962,500(93	)
RCG Carpathia Master Fund, Ltd.(37)	1,887,500	(94)	2.2	%	1,887,500(94	)
Leon Recanati	83,334		*		83,334
Ronald J. and Patricia E. Reed	1,000		*		1,000
Robeco WPG Opportunistic Value Fund, L.P. (7)	175,200	(95)	*		175,200(95	)
Robeco WPG Opportunistic Value Overseas, L.P. (7)	40,700	(96)	*		40,700(96	)
Jay Rodin	1,290,176	(97)	1.5	%	1,290,176(97	)
Herman Kenneth Rothberger	4,000	(98)	*		4,000(98	)
S. Goldman Advisors Limited (38)	361,616	(99)	*		361,616(99	)
Satellite Overseas Fund, Ltd (39)	9,764,587	(100)	10.8	%	9,764,587(100	)
Satellite Fund II, LP (39)	4,182,411	(101)	4.8	%	4,182,411(101	)
Satellite Fund IV, LP (39)	786,980	(102)	*		786,980(102	)
Satellite Overseas Fund V Ltd. (39)	947,795	(103)	1.1	%	947,795(103	)
Satellite Overseas Fund VI, Ltd. (39)	447,527	(104)	*		447,527(104	)
Satellite Overseas Fund VII, Ltd. (39)	194,189	(105)	*		194,189(105	)
Satellite Overseas Fund VIII, Ltd. (39)	383,670	(106)	*		383,670(106	)
Satellite Overseas Fund IX, Ltd. (39)	840,849	(107)	1.0	%	840,849(107	)
Satellite Strategic Finance Partners, Ltd. (39)	1,950,919	(108)	2.3	%	1,950,919(108	)
John D. and Kristi D. Schiller	400,000	(109)	*		400,000(109	)
John Daniel Schiller, Jr.	8,816,701	(110)	10.2	%	8,816,701(110	)

55

	Beneficial Ownership Prior to the Offering (1)
Name of Selling Stockholder	Shares	Percentage (2)	Shares Offered

John D. Schiller, Sr. (40)	150,000				150,000
Scoggin Capital Management LP II (20)	3,975,000	(111)	4.5	%	3,975,000(111	)
Scoggin International Fund, Ltd. (20)	3,625,000	(112)	4.1	%	3,625,000(112	)
Seneca Capital International Ltd. (21)	11,520,203	(113)	12.6	%	11,520,203(113	)
Seneca Capital LP (21)	3,128,899	(114)	3.6	%	3,128,899(114	)
Seneca Capital LP II (21)	1,900	(115)	*		1,900(115	)
Silver Sands Fund LLC (30)	466,500	(116)	*		466,500(116	)
Southport Energy Plus Offshore Fund, Inc. (41)	1,852,900	(117)	2.2	%	1,852,900(117	)
Southport Energy Plus Partners, L.P. (41)	2,308,600	(118)	2.7	%	2,308,600(118	)
Sunrise Equity Partners, L.P. (42)	5,000,001	(119)	5.7	%	5,000,001(119	)
Sunrise Foundation Trust (43)	1,548,444	(43)	1.8	%	1,548,444(43	)
Sunrise Securities Corp. (43) (44)	520,001	(120)	*		520,001(120	)
The Apogee Fund, Ltd. (39)	1,862,242	(121)	2.3	%	1,862,242(121	)
The Exploitation Company LLP (45)	2,950,004	(122)	3.4	%	2,950,004(122	)
The Ospraie Portfolio Ltd. (46)	6,071,668	(123)	7.0	%	6,071,668(123	)
The Schiller Children’s 2005 Irrevocable Trust (40)	500,000		*		500,000
W B Nominees Ltd. (47)	490,000	(124)	*		490,000(124	)
Steven Albert Weyel	2,983,333	(125)	3.5	%	2,983,333(125	)
Eric Lawrence White	75,000	(126)	*		75,000(126	)
Paul Barrington Williams	7,800	(127)	*		7,800(127	)
Wimbledon Sand Spring (48)	7,500		*		7,500
Windmill Master Fund LP (23)	15,048,901	(128)	15.2	%	15,048,901(128	)
Woodland Partners (49)	569,000	(129)	*		569,000(129	)
Worldwide Transactions Limited (5)	13,688	(130)	*		13,688(130	)
Xerion Partners II Master Fund Limited (50)	200,000		*		200,000
Total	148,503,324				148,503,324

*	Less than 1%
(1)	Beneficial ownership is determined in accordance with the rules of the Security Exchange Commission and generally includes voting or investment power with respect to securities. Shares of common stock subject to options, warrants and unit purchase options currently exercisable or convertible, or exercisable or convertible within 60 days of March 23, 2007 are deemed outstanding for computing the beneficial ownership percentage of the person holding such option, warrant or unit purchase option but are not deemed outstanding for any other purpose.
(2)	Percentage prior to the offering is based on 84,049,115 shares of common stock outstanding as of March 23, 2007.
(3)	Includes 1,200,000 common shares underlying warrants. Sean O’Flanagan is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(4)	Michael S. Rosen and William Fertig of Context Capital Management, LLC are deemed to hold investment power and voting control over shares held by this selling shareholder.
(5)	Konrad Ackerman is deemed to hold investment power and voting control over shares held by this selling shareholder.
(6)	Mark Corigliano is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(7)	Richard Shuster and Dan Vanizort are deemed to hold investment power and voting control over the shares held by this selling stockholder. This selling stockholder is not a broker-dealer; however, it is an affiliate of a broker-dealer. The shares held by this selling stockholder were purchased in the ordinary course of business and, at the time of purchase, this selling stockholder had no agreements or understanding, directly or indirectly, with any party to distribute the shares.
(8)	Clint D. Coghill of Coghill Capital Management, L.L.C., the investment manager to COM Master Qualified Fund, Ltd., exercises sole voting and dispositive powers with respect to the shares registered on behalf of COM Master Qualified Fund, Ltd. Clint D. Coghill and Coghill Capital Management, L.L.C. each disclaim beneficial ownership of the shares held by COM Master Qualified Fund, Ltd.
(9)	David K. Sherman is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(10)	J. Christopher Young and C. Michael Vaughn, Jr. are deemed to hold investment power and voting control over shares held by this selling shareholder. This selling shareholder is a broker dealer.
(11)	The investment manager of DKR SoundShore Oasis Holding Fund Ltd. (the “Fund”) is DKR Oasis Management Company LP (the “Investment Manager”). The Investment Manager has the authority to do any and all acts on behalf of the Fund, including voting any shares held by the Fund. Mr. Seth Fischer is the managing partner of Oasis Management Holdings LLC, one of the general partners of the Investment Manager. Mr. Fischer has ultimate responsibility for investments with respect to the Fund. Mr. Fischer disclaims beneficial ownership of the shares.

56

(12)	David Faucett is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(13)	Lee Hunt is deemed to hold investment power and voting control over shares held by this selling shareholder.
(14)	Jean Bernard Guyon is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(15)	Includes 361,616 common shares underlying warrants 928,551 common shares underlying 309,517 unit purchase options. Mr. Sheldon Goldman is an employee of Sunrise Securities Corp. and received his holdings as investment banking compensation, other than 361,616 warrants which were purchased in the open market and are owned by S. Goldman Advisors Limited. Mr. Sheldon Goldman is the sole owner of S. Goldman Advisors Limited.
(16)	Includes 358,755 common shares underlying 119,585 unit purchase options. Mr. David Goodfriend is an employee of Sunrise Securities Corp. and received his holdings as investment banking compensation.
(17)	Eileen Rominger is deemed to hold investment power and voting control over shares held by this selling shareholder.
(18)	Daniel Nir is deemed to hold investment power and voting control over shares held by this selling shareholder.
(19)	Daniel Nir is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(20)	Craig Effron and Curtis Schenker as Managing Members of Scoggin LLC, its investment manager are deemed to hold investment power and voting control over the shares held by the stockholder.
(21)	Douglas A. Hirsch is deemed to hold investment power and voting control over the shares held by this selling stockholder. Mr. Hirsch disclaims beneficial ownership of the securities except to the extent of his pecuniary interest therein.
(22)	C. Michael Vaughn and Robert Lee are deemed to hold investment power and voting control over shares held by this selling shareholder.
(23)	Stan Druckenmiller is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(24)	Brett Cohen is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(25)	JMG Capital Partners, L.P. (“JMG Partners”) is a California limited partnership. Its general partner is JMG Capital Management, LLC (the “Manager”), a Delaware limited liability company and an investment adviser that has voting and dispositive power over JMG Partners’ investments, including the shares. The equity interests of the Manager are owned by JMG Capital Management, Inc., (“JMG Capital”) a California corporation, and Asset Alliance Holding Corp., a Delaware corporation. Jonathan M. Glaser is the Executive Officer and Director of JMG Capital and has sole investment discretion over JMG Partners’ portfolio holdings.
(26)	JMG Triton Offshore Fund, Ltd. (the “Fund”) is an international business company organized under the laws of the British Virgin Islands. The Fund’s investment manager is Pacific Assets Management LLC, a Delaware limited liability company (the “Manager”) that has voting and dispositive power over the Fund’s investments, including the shares. The equity interests of the Manager are owned by Pacific Capital Management, Inc., a California corporation (“Pacific”) and Asset Alliance Holding Corp., a Delaware corporation. The equity interests of Pacific are owned by Messrs. Roger Richter, Jonathan M. Glaser and Daniel A. David. Messrs. Glaser and Richter have sole investment discretion over the Fund’s portfolio holdings.
(27)	John Lovoi is deemed to hold investment power and voting control over shares held by this selling shareholder.
(28)	Includes 24,501 common shares underlying 8,167 unit purchase options. Mr. Serge Moyal is an employee of Sunrise Securities Corp. and received his holdings as investment banking compensation.
(29)	Ralph Colve and Diane Schaefer are deemed to hold investment power and voting control over 550 and 450 shares, respectively, held by this selling stockholder.
(30)	Brian Taylor and Aaron Yeary are deemed to hold investment power and voting control over shares held by this selling shareholder.
(31)	Keith A. Goodman is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(32)	Jonathan Schneider and Michael Falken as authorized signatories of Novator Partners LLP are deemed to hold investment power and voting control over shares held by this selling shareholder.
(33)	James Cacioppo and Nat Klipper are deemed to hold investment power and voting control over shares held by this selling shareholder.
(34)	Ramius Capital Group, L.L.C. (“Ramius Capital”) is the investment adviser of Portside Growth and Opportunity Fund (“Portside”) and consequently has voting control and investment discretion over securities held by Portside. Ramius Capital disclaims beneficial ownership of the shares held by Portside. Peter A. Cohen, Morgan B. Stark, Thomas W. Strauss and Jeffrey M. Solomon are the sole managing members of C4S & Co., L.L.C., the sole managing member of Ramius Capital. As a result, Messrs. Cohen, Stark, Strauss and Solomon may be considered beneficial owners of any shares deemed to be beneficially owned by Ramius Capital. Messrs. Cohen, Stark, Strauss and Solomon disclaim beneficial ownership of these shares. This selling stockholder is not a broker-dealer; however, it is an affiliate of a broker-dealer. The shares held by this selling stockholder were purchased in the ordinary course of business and, at the time of purchase, this selling stockholder had no agreements or understandings, directly or indirectly, with any party to distribute the shares.
(35)	Pursuant to an investment management agreement, RG Capital Management, L.P. (“RG Capital”) serves as the investment manager of Radcliffe SPC, Ltd.’s Class A Convertible Crossover Segregated Portfolio. RGC Management Company, LLC (“Management”) is the general partner of RG Capital. Steve Katznelson and Gerald Stahlecker serve as the managing members of Management. Each of RG Capital, Management and Messrs. Katznelson and Stahlecker disclaim beneficial ownership of the securities owned by Radcliffe SPC, Ltd. for and on behalf of the Class A Convertible Crossover Segregated Portfolio.
(36)	Ramius Capital Group, L.L.C. (“Ramius Capital”) is the sole member of Ramius Securities, L.L.C. (“ Ramius Securities”) and consequently has voting control and investment discretion over securities held by Ramius Securities. Ramius Capital disclaims beneficial ownership of the shares held by Ramius Securities. Peter A. Cohen, Morgan B. Stark, Thomas W. Strauss and Jeffrey M. Solomon are the sole managing members of C4S & Co., L.L.C., the sole managing member of Ramius Capital. As a result, Messrs. Cohen, Stark, Strauss and Solomon may be considered beneficial owners of any shares deemed to be beneficially owned by Ramius Capital. Messrs. Cohen, Stark, Strauss and Solomon disclaim beneficial ownership of these shares.
(37)	The investment advisor to RCG Carpathia Master Fund, Ltd. is Ramius Capital Group, L.L.C. (“Ramius Capital”). An affiliate of Ramius Capital Group, L.L.C.,, is a NASD member. However, this affiliate will not sell any shares to be offered by RCG Carpathia Master Fund, Ltd. through the prospectus and will receive no compensation whatsoever in conjunction with sales of shares by RCG Carpathia Master Fund, Ltd. through the prospectus.Peter A. Cohen, Morgan B. Stark, Thomas W. Strauss and Jeffrey M. Solomon are the solemanaging members of C4S & Co., L.L.C., the sole managing member of Ramius Capital.. As a result, Messrs. Cohen, Stark, Strauss and Solomon may beconsidered beneficial owners of any shares deemed to be beneficially owned by Ramius Capital. Messrs. Cohen, Stark, Strauss and Solomon disclaim beneficial ownership of these shares.

57

(38)	Sheldon Goldman is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(39)	The discretionary investment manager of the selling stockholder is Satellite Asset Management, L.P. (“SAM”). The controlling entity of SAM is Satellite Fund Management, LLC (“SFM”). The managing members of SFM are Lief Rosenblatt, Mark Sonnino & Gabe Nechamkin. SAM, SFM and each named individual disclaims beneficial ownership of the securities.
(40)	John D. Schiller, Jr. retains voting control over these securities but otherwise disclaims beneficial ownership.
(41)	Anthony Giammalua as an authorized signatory of Sound Energy Partners, Inc., the investment manager, is deemed to hold investment power and voting control over shares held by this selling shareholder.
(42)	Nathan Low, Amnon Mandelbaum and Marilyn Adler are deemed to hold investment power and voting control over the shares held by this selling stockholder. Sunrise Equity Partners, L.P. is not a broker-dealer; however, it is an affiliate of a broker dealer. The shares held by Sunrise Equity Partners, L.P. were purchased in the ordinary course of business and, at the time of purchase, Sunrise Equity Partners, L.P. had no agreements or understandings, directly or indirectly, with any party to distribute the shares. Sunrise Securities Corp. has advised us that it is a broker-dealer and that it received registrable securities as compensation for investment banking activities to us. Sunrise Securities Corp. has also advised us that it acquired the securities being registered for resale in the ordinary course of business, and at the time of the acquisition, Sunrise Securities Corp. had no agreements or understandings, directly or indirectly, with any person to distribute the securities.
(43)	Includes 1,548,444 common shares underlying 516,148 unit purchase options owned by the Sunrise Foundation Trust (“SFT”). SFT disclaims beneficial ownership of all of the securities of the Company owned by Mr. Nathan Low, and excludes (i) 2,695,303 common shares underlying warrants owned by Mr. Nathan Low and (ii) 6,193,776 common shares underlying 2,064,592 unit purchase options owned by Mr. Nathan Low. SFT may be deemed an affiliate of Sunrise Securities Corp. SFT’s holdings were originally issued in connection with an investment banking fee payable to SSC and were than donated to SFT, a charitable foundation. Mr. Nathan Low disclaims beneficial ownership of the securities owned by SFT because they are owned by a charitable foundation. Mr. Nathan Low is one of two trustees (the other trustee is his wife, Mrs. Lisa Low) of SFT. Mr. Nathan Low would share voting interest with his wife (Mrs. Lisa Low) over these shares upon exercise and issuance.
(44)	Nathan Low is deemed to hold investment power and voting control over the shares held by this selling stockholder. Sunrise Equity Partners, L.P. is not a broker-dealer; however, it is an affiliate of a broker dealer. The shares held by Sunrise Equity Partners, L.P. were purchased in the ordinary course of business and, at the time of purchase, Sunrise Equity Partners, L.P. had no agreements or understandings, directly or indirectly, with any party to distribute the shares. Sunrise Securities Corp. has advised us that it is a broker-dealer and that it received registrable securities as compensation for investment banking activities to us. Sunrise Securities Corp. has also advised us that it acquired the securities being registered for resale in the ordinary course of business, and at the time of the acquisition, Sunrise Securities Corp. had no agreements or understandings, directly or indirectly, with any person to distribute the securities.
(45)	John Schiller is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(46)	Pursuant to an investment management agreement, Ospraie Management, LLC (“Ospraie Management”) serves as investment manager to the The Ospraie Portfolio Ltd. (“Ospraie”). As such, Ospraie Management has been granted investment discretion over portfolio investments held for the account of Ospraie. Ospraie Holding I, L.P. (“Ospraie Holding”) is the managing member of Ospraie Management. Ospraie Management, Inc. (“Ospraie Inc.”) is the general partner of Ospraie Holding. Mr. Dwight Anderson is the President and controlling equity owner of Ospraie Inc. and, in such capacity, may be deemed to have voting and dispositive power over the securities held for the account of Ospraie. Mr. Anderson disclaims any beneficial ownership in such securities except to the extent of any pecuniary interest therein.
(47)	Fiona Atkins, Dr. J.S. Price, Mrs. L. Kilpatrick, David M. Rogers and Mrs. S. Fletcher are deemed to hold investment power and voting control over the shares held by this selling stockholder. This selling shareholder is a broker-dealer and an underwriter.
(48)	Includes 300,000 common shares underlying warrants.
(49)	Barry and Marilyn Rubenstein are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(50)	Daniel Arbess is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(51)	Includes 38,065 common shares underlying warrants and 47,616 common shares underlying 15,872 unit purchase options. Each unit purchase option is exercisable into one common share and two warrants, and each of the two warrants are then exercisable into one common share. Thus, there are three common shares underlying each unit purchase option. Mr. Abitbol is an employee of Sunrise Securities Corp. and received his holdings as investment banking compensation, other than his 38,065 warrants acquired in the open market.
(52)	Includes 4,738 common shares underlying warrants, all of which are offered.
(53)	Includes 166,668 common shares underlying warrants, all of which are offered.
(54)	Includes 26,625 common shares underlying warrants, all of which are offered.
(55)	Includes 44,600 common shares underlying warrants.
(56)	Includes 19,400 common shares underlying warrants, all of which are offered.
(57)	Includes 42,000 common shares underlying warrants.
(58)	Includes 88,279 common shares underlying warrants, all of which are offered.
(59)	Includes 43,125 common shares underlying warrants, all of which are offered.
(60)	Includes 3,888 common shares underlying warrants, all of which are offered.

58

(61)	Includes 367,500 common shares underlying 122,500 unit purchase options. Mr. Robert Fuchs is an employee of Sunrise Securities Corp. and received his holdings as investment banking compensation.
(62)	Includes 52,500 common shares underlying 17,500 unit purchase options.
(63)	Includes 882,019 common shares underlying warrants, all of which are offered.
(64)	Includes 1,072,500 common shares underlying warrants, all of which are offered.
(65)	Includes 305,250 common shares underlying warrants, all of which are offered.
(66)	Includes 1,285,167 common shares underlying warrants.
(67)	Includes 87,083 common shares underlying warrants, all of which are offered.
(68)	Includes 119,413 common shares underlying warrants, all of which are offered.
(69)	Includes 15,000 common shares underlying warrants.
(70)	Includes 265,000 common shares underlying warrants.
(71)	Includes 306,032 common shares underlying warrants.
(72)	Includes 128,390 common shares underlying warrants.
(73)	Includes 1,325,000 common shares underlying warrants, all of which are offered.
(74)	Includes 4,713 common shares underlying warrants, all of which are offered.
(75)	Includes 211,100 common shares underlying warrants.
(76)	Includes 417,589 common shares underlying warrants, all of which are offered.
(77)	Includes 1,837,500 common shares underlying warrants.
(78)	Includes 1,837,500 common shares underlying warrants.
(79)	Includes 170,668 common shares underlying warrants, all of which are offered.
(80)	Includes 96,000 common shares underlying warrants, all of which are offered.
(81)	Includes 30,000 common shares underlying 10,000 unit purchase options. Ms. Marcia Kucher is an employee of Sunrise Securities Corp. and received her holdings as investment banking compensation.
(82)	Includes (i) 3,675,303 common shares underlying warrants owned by Mr. Nathan Low and (ii) 6,193,776 common shares underlying 2,064,592 unit purchase options owned by Mr. Nathan Low. Does not include (i) 20,000 common shares and 500,001 common shares underlying 166,667 unit purchase options owned by Sunrise Securities Corp. (“SSC”), (ii) 2,059,167 shares of common stock and 2,940,834 common shares underlying warrants owned by Sunrise Equity Partners, L.P. (“SEP”) and (iii) 1,548,444 common shares underlying 516,148 unit purchase options owned by SFT. Mr. Nathan Low disclaims beneficial ownership of all of our securities owned by the Sunrise Foundation Trust (“SFT”) and Sunrise Equity Partners, L.P. (“SEP”) (other than Mr. Nathan Low’s ownership of our securities as a result of his ownership of limited partnership interests of SEP). Mr. Nathan Low is the sole shareholder of SSC. Mr. Nathan Low is one of two trustees (the other trustee is his wife, Mrs. Lisa Low) of SFT. Level Counter, LLC (“LC”) is the general partner of SEP, and LC controls the investment power with respect to the securities of the Company owned by SEP. The investment decisions of LC require the unanimous vote of all three of Ms. Marilyn Adler, Mr. Nathan Low and Mr. Amnon Mandelbaum. Nathan Low is an employee of SSC and received his holdings as investment banking compensation, other than the 2,695,303 common shares underlying warrants which were acquired from purchases on the open market and other than the 20,000 shares of common stock also purchased on the open market.

59

(83)	Includes 791,001 common shares underlying unit purchase options.
(84)	Includes 28,044 common shares underlying warrants, all of which are offered.
(85)	Includes 3,228,804 common shares underlying 1,076,268 unit purchase options owned by Mr. Amnon Mandelbaum. Does not include 2,059,167 shares of common stock and 2,940,834 common shares underlying warrants owned by Sunrise Equity Partners, L.P. (“SEP”). Mr. Amnon Mandelbaum disclaims beneficial ownership of all of our securities owned by SEP (other than Mr. Amnon Mandelbaum’s ownership of our securities as a result of his ownership of limited partnership interests of SEP). Level Counter, LLC (“LC”) is the general partner of SEP, and LC controls the investment power with respect to the securities of the Company owned by SEP. The investment decisions of LC require the unanimous vote of all three of Ms. Marilyn Adler, Mr. Nathan Low and Mr. Amnon Mandelbaum. Amnon Mandelbaum is an employee of Sunrise Securities Corp. and received his holding as investment banking compensation.
(86)	Includes 66,666 common shares underlying warrants, all of which are offered.
(87)	Includes 7,728,500 common shares underlying warrants, all of which are offered.
(88)	Includes 50,000 common shares underlying warrants.
(89)	Includes 725,000 common shares underlying warrants, all of which are offered.
(90)	Paul Candies, Otto Candies, Jr. and Kevin Candies are deemed to hold investment power and voting control over shares held by this selling shareholder.
(91)	Chris Kuchanny is deemed to hold investment power and voting control over shares held by this selling shareholder.
(92)	Includes 500,000 common shares underlying warrants.
(93)	Includes 962,500 common shares underlying warrants, all of which are offered.
(94)	Includes 1,887,500 common shares underlying warrants, all of which are offered.
(95)	Includes 175,200 common shares underlying warrants.
(96)	Includes 40,700 common shares underlying warrants.
(97)	Includes 361,616 common shares underlying warrants and 928,560 common shares underlying 309,517 unit purchase options. Mr. Jay Rodin is an employee of Sunrise Securities Corp. and received his holdings as investment banking compensation, other than his 361,616 warrants acquired in the open market.
(98)	Includes 4,000 common shares underlying warrants.
(99)	Includes 361,616 common shares underlying warrants by S. Goldman Advisors Ltd. Mr. Sheldon Goldman is the sole owner of S. Goldman Advisors Limited.
(100)	Includes 6,125,105 common shares underlying warrants.
(101)	Includes 2,673,192 common shares underlying warrants.
(102)	Includes 494,663 common shares underlying warrants.
(103)	Includes 605,182 common shares underlying warrants.
(104)	Includes 300,293 common shares underlying warrants.
(105)	Includes 89,695 common shares underlying warrants.
(106)	Includes 155,017 common shares underlying warrants.
(107)	Includes 514,539 common shares underlying warrants.
(108)	Includes 908,377 common shares underlying warrants.
(109)	Includes 400,000 common shares underlying warrants.
(110)	Includes 2,725,001 common shares underlying warrants,.
(111)	Includes 2,850,000 common shares underlying warrants.

60

(112)	Includes 2,500,000 common shares underlying warrants.
(113)	Includes 7,125,802 common shares underlying warrants.
(114)	Includes 1,793,166 common shares underlying warrants.
(115)	Includes 1,900 common shares underlying warrants.
(116)	Includes 466,500 common shares underlying warrants, all of which are offered.
(117)	Includes 1,007,300 common shares underlying warrants, all of which are offered.
(118)	Includes 1,287,700 common shares underlying warrants, all of which are offered.
(119)	Includes 2,059,167 shares of common stock and 2,940,834 common shares underlying warrants owned by Sunrise Equity Partners, L.P. (“SEP”). Level Counter, LLC (“LC”) is the general partner of SEP, and LC controls the investment power with respect to the securities of the Company owned by SEP. The investment decisions of LC require the unanimous vote of all three of Ms. Marilyn Adler, Mr. Nathan Low and Mr. Amnon Mandelbaum. SEP disclaims beneficial ownership of all of the securities of the Company owned by Mr. Nathan Low, Mr. Amnon Mandelbaum, Ms. Marilyn Adler (except for the ownership of securities of the Company as a result of the respective ownership of limited partnership interests of SEP held by Mr. Nathan Low, Mr. Amnon Mandelbaum and Ms. Marilyn Adler), Sunrise Securities Corp. (“SSC”) and the Sunrise Foundation Trust (“SFT”), and excludes (i) 2,695,303 common shares underlying warrants owned by Mr. Nathan Low, (ii) 6,193,776 common shares underlying 2,064,592 unit purchase options owned by Mr. Nathan Low (iii) 3,228,804 common shares underlying 1,076,268 unit purchase options owned by Mr. Amnon Mandelbaum, (iv) 20,000 common shares and 500,001 common shares underlying 166,667 unit purchase options owned by SSC and (v) 1,548,444 common shares underlying 516,148 unit purchase options owned by the SFT. SEP acquired its holdings by participation as a purchaser in the initial offering and admission of the Company to the AIM.
(120)	Includes 500,001 common shares underlying 166,667 unit purchase options.
(121)	Includes 1,154,273 common shares underlying warrants.
(122)	Includes 2,833,334 common shares underlying warrants.
(123)	Includes 2,416,668 common shares underlying warrants.
(124)	Includes 490,000 common shares underlying warrants.
(125)	Includes 383,333 common shares underlying warrants, all of which are offered.
(126)	Includes 50,000 common shares underlying warrants.
(127)	Includes 7,800 common shares underlying warrants.
(128)	Includes 7,748,900 common shares underlying warrants.
(129)	Includes 376,000 common shares underlying warrants.
(130)	Includes 6,188 common shares underlying warrants, all of which are offered.

61

LEGAL MATTERS

The validity of the shares offered hereby will be passed upon for us by Appleby Hunter Bailhache, our Bermuda counsel.

EXPERTS

The consolidated balance sheet of Energy XXI (Bermuda) Limited as of June 30, 2006 and the related consolidated statements of income, stockholders’ equity, and cash flows from the period from inception (July 25, 2005) through June 30, 2006, the statements of revenues and direct operating expenses of certain oil and gas properties referred to therein as the Carve-Out Financial Statements for Castex for the twelve month periods ending June 30, 2006, 2005 and 2004, and the statements of revenues and direct operating expenses of certain oil and gas properties referred to therein as the Carve-Out Financial Statements for Pogo for each of the years in the three year period ended December 31, 2006, included in this prospectus have been audited by UHY LLP, independent registered public accounting firm, and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The combined balance sheets of Marlin Energy Offshore L.L.C., Marlin Texas GP, L.L.C. and Marlin Texas, L.P. as of March 31, 2006, December 31, 2005, 2004 and 2003 and the related combined statements of operations, changes in member’s equity and cash flows for the three month period ended March 31, 2006 and each of the years ended December 31, 2005, 2004 and 2003 included in this prospectus have been audited by Grant Thornton LLP, independent registered public accounting firm, and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The information included in this prospectus regarding estimated quantities of our proved reserves as of June 30, 2006 were prepared or derived from estimates prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Miller and Lents, Ltd., independent petroleum engineers, also prepared estimated quantities of proved reserves for the Castex properties we acquired in July 2006.Ryder Scott Company, LP, independent petroleum engineers, also prepared estimated quantities of proved reserves for the Pogo Properties we acquired on June 8, 2007. These estimates are included in this prospectus in reliance upon the authority of these firms as experts in these matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the common stock being sold in this offering. This prospectus, which forms part of the registration statement, does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common stock being sold in this offering, we refer you to the registration statement and the exhibits and schedules filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other document are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and is qualified in all respects by the filed exhibit. The registration statement, including exhibits and schedules filed, as well as reports, proxy statements and other information we are required to file under the Securities Exchange Act of 1934, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, NE, Washington, D.C. 20549, and copies of all or any part of it may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. The other information we file with the SEC is not part of the registration statement of which this prospectus forms a part.

62

INDEX TO FINANCIAL STATEMENTS

Contents	Page
Energy XXI (Bermuda) Limited Consolidated Financial Statements (June 30, 2006)		F-2
Energy XXI (Bermuda) Limited Consolidated Financial Statements (March 31,2007)		F-21
Carve-Out Financial Statements for Castex		F-35
Marlin Energy Offshore L.L.C., Marlin Texas GP, L.L.C. and Marlin Texas, L.P. Combined Financial Statements		F-41
Carve-Out Financial Statements for the Pogo Properties		F-53
Energy XXI (Bermuda) Limited Pro Forma Financial Statements		F-60

F-1

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

F-2

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 sheet of Energy XXI (Bermuda) Limited (a Bermuda Corporation) and subsidiaries (the “Company”) as of June 30, 2006 and the related consolidated statements of income, stockholders’ equity, and cash flows 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 audit.

We conducted our audit 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. 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 audit 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, 2006, and the consolidated results of their operations and their cash flows 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

October 17, 2006

F-3

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED BALANCE SHEET

JUNE 30, 2006

(In Thousands, except share information)

ASSETS
Current assets:
Cash and cash equivalents	$	62,389
Receivables:
Oil and natural gas sales		19,325
Joint interest billings		11,173
Acquisition		14,070
Stock subscription		7,326
Insurance		39,801
Prepaid expenses and other current assets		9,200
Royalty deposit		2,175
Derivative financial instruments		7,752
TOTAL CURRENT ASSETS		173,211
PROPERTY AND EQUIPMENT, net of accumulated depreciation, depletion, and amortization Oil and natural gas properties—full cost method of accounting, including $50,840 of unproved oil and natural gas properties		447,852
Other property and equipment		1,569
TOTAL PROPERTY AND EQUIPMENT, NET		449,421
Escrow deposit and acquisition costs		10,025
Derivative financial instruments		5,856
Deferred income taxes		1,780
Debt issuance costs, net of accumulated amortization of $306		3,678
TOTAL ASSETS	$	643,971
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	23,281
Advances from joint interest partners		6,211
Accrued liabilities		11,463
Income and franchise taxes payable		913
Deferred income taxes		143
Derivative financial instruments		948
Current maturities of long-term debt		9,584
TOTAL CURRENT LIABILITIES		52,543
Long-term debt, less current maturities		200,064
Asset retirement obligations		37,844
Derivative financial instruments		590
Other liabilities		221
TOTAL LIABILITIES		291,262
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value, 2,500,000 shares authorized and no shares issued		—
Common stock, $0.001 par value, 396,500,624 shares authorized and 80,645,129 issued at June 30, 2006		81
Additional paid-in capital		350,238
Retained earnings		6,942
Accumulated other comprehensive loss, net of tax benefit		(4,552	)
TOTAL STOCKHOLDERS’ EQUITY		352,709
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	643,971

The accompanying notes are an integral part of these consolidated financial statements.

F-4

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED STATEMENT OF INCOME

INCEPTION (JULY 25, 2005) THROUGH JUNE 30, 2006

(In Thousands, except share and per share information)

REVENUES
Oil sales	$	29,056
Natural gas sales		18,056
TOTAL REVENUES		47,112
COSTS AND EXPENSES
Lease operating expense		9,902
Production taxes and transportation		84
Depreciation, depletion and amortization		20,357
Accretion of asset retirement obligation		738
General and administrative expense		4,361
Loss on derivative financial instruments		68
TOTAL COSTS AND EXPENSES		35,510
OPERATING INCOME		11,602
OTHER INCOME (EXPENSE)
Interest income		5,000
Interest expense		(7,933	)
INCOME BEFORE PROVISION FOR INCOME TAXES		8,669
PROVISION FOR INCOME TAXES		1,727
NET INCOME	$	6,942
EARNINGS PER SHARE
Basic	$	0.14
Diluted	$	0.12
WEIGHTED AVERAGE NUMBER OF COMMON STOCK OUTSTANDING
Basic		49,839,179
Diluted		58,474,771

The accompanying notes are an integral part of these consolidated financial statements.

F-5

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

INCEPTION (JULY 25, 2005) THROUGH JUNE 30, 2006

(In Thousands)

	Preferred Stock				Common Stock						Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Shares		Amount		Shares			Amount
Issuance of common stock and warrants at inception (July 25, 2005)		—	$	—		12,500		$	13		$	9		$	—	$	—		$	22
Issuance of common stock and warrants on October 20, 2005—AIM Placement		—		—		50,000			50			308,107			—		—			308,157
Share issuance costs—AIM Placement		—		—		—			—			(30,465	)		—		—			(30,465	)
Common stock repurchased—private placement		—		—		(3,499	)		(3	)		(19,568	)		—		—			(19,571	)
Common stock issued—private placement		—		—		3,499			3			19,593			—		—			19,596
Common stock issued—warrant exercise		—		—		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 as of June 30, 2006		—	$	—		80,645		$	81		$	350,238		$	6,942		(4,552	)	$	352,709

The accompanying notes are an integral part of these consolidated financial statements.

F-6

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED STATEMENT OF CASH FLOWS

INCEPTION (JULY 25, 2005) THROUGH JUNE 30, 2006

(In Thousands)

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	6,942
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense		814
Unrealized gain on derivative financial instrument		(119	)
Accrued interest classified as long-term debt		100
Put premium amortization		1,172
Accretion of asset retirement obligations		738
Depletion, depreciation, and amortization		20,357
Amortization of debt issuance costs		494
Changes in operating assets and liabilities:
Increases in receivables		(26,912	)
Increases in prepaid expenses and other current assets		(5,815	)
Increases in accounts payable and other liabilities		14,297
NET CASH PROVIDED BY OPERATING ACTIVITIES		12,068
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition		(448,374	)
Capital expenditures		(29,426	)
Insurance payments received		10,323
Purchase of derivative instruments		(3,168	)
Escrow deposit and acquisition costs		(10,025	)
NET CASH USED IN INVESTING ACTIVITIES		(480,670	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of common stock		384,872
Payments for stock issuance costs		(22,308	)
Payments to re-purchase and cancel common stock		(19,571	)
Proceeds from note purchase agreement		14,150
Payment on note purchase agreement		(14,150	)
Proceeds from first lien revolver		117,500
Proceeds from second lien facility		75,000
Debt issuance costs		(4,172	)
Payments on put financing		(330	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		530,991
NET INCREASE IN CASH AND CASH EQUIVALENTS		62,389
CASH AND CASH EQUIVALENTS, beginning of period		—
CASH AND CASH EQUIVALENTS, end of period	$	62,389

The accompanying notes are an integral part of these consolidated financial statements.

F-7

ENERGY XXI (BERMUDA) LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

NOTE 1—ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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. The Company is engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico.

On October 20, 2005, the Company completed a placement on the London Stock Exchange Alternative Investment Market (the “AIM”), consisting of 50 million units (the “Placement”). The units consisted of one share of the Company’s common stock with a par value of $.001, and two redeemable common share purchase warrants (the “Warrants”), together (the “Units”). The Company received proceeds of approximately $277.7 million, net of issuance costs of approximately $22.3 million, issuing 50 million units at $6 per unit on the AIM. Approximately $275 million or $5.50 per share issued in the Placement was placed into a restricted trust account in Bermuda (the “Trust”) and the remaining was deposited into the Company’s bank account for future business expenses.

On February 21, 2006, EGC entered into a definitive agreement with Marlin Energy, L.L.C. (“Marlin”) to acquire 100% 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 Company, as part of the post closing settlement with Marlin, is due $14.1 million. See NOTE 3.

The Oil and Gas Assets are comprised of interests in various oil and natural gas properties located on the Outer Continental Shelf in shallow waters of the U.S. Gulf of Mexico (“GOM”) and onshore the U.S. Gulf Coast. The Company will operate approximately 70% of the net proved reserves.

Simultaneous with signing the agreement, the Company placed a $500,000 earnest money deposit in escrow. On March 2, 2006, the Company, through Energy XXI (US Holdings) Limited (“US Holdings”), a wholly owned subsidiary of Energy XXI, entered into a note purchase agreement with Satellite Senior Income Fund, LLC (“Satellite”), whereby the Company agreed to sell $17.5 million aggregate principal amount of its 6.5% senior notes due May 11, 2006 for a price of $14.15 million. On March 2, 2006, the Company increased the earnest money deposit to $10 million, to avoid paying the seller 7% interest on the $421 million initial purchase price of the acquisition from January 1, 2006 until the closing. The Company used approximately $4 million to purchase crude oil put derivative instruments to partially hedge the acquisition’s cash flows, and approximately $150,000 to pay for the lenders’ legal costs. The financing was structured to have no recourse to the Company (other than the security interest in the derivatives, contract rights to the purchase and sale agreement, and right to any proceeds from the escrow account).

Completion of the acquisition was contingent upon stockholders’ approval, financing and re-admission of the Energy XXI ordinary shares and warrants to trading on AIM. On March 31, 2006, the Company received shareholder approval of the acquisition with approximately 83.8% of the total outstanding shares voting, of which 93.3% voted in favor of the transaction, subject to 3,499,376 shares that were put to the Company for their pro rata share of the funds in the Trust (approximately $5.59/share). These repurchases were completed on April 4, 2006.

On April 4, 2006, the acquisition was funded with a portion of the cash proceeds from the placing conducted in October 2005 at the time of the Company’s admission and trading on the AIM. The net placing proceeds, approximating $282.6 million of which included approximately $5 million of interest income, were released from the Trust upon majority shareholder approval of the acquisition. Of the $282.6 million, approximately $19.6 million was used to repurchase stock from investors, leaving approximately $263 million to fund the acquisition, repay the note purchase agreement with Satellite, and pay for certain transaction and working capital costs. To fund the balance of the costs at closing, the Company obtained commitments from The Royal Bank of Scotland and BNP Paribas to arrange for $375 million of financing facilities of which $220 million was available at closing. At closing, the Company had outstanding $180 million of debt facilities plus an additional $5 million of Letters of Credit. On April 25, 2006, the Company issued 3,499,376 shares at $5.60/share for total proceeds of approximately $19.6 million.

F-8

Principles of Consolidation: The Company’s consolidated financial statements include the accounts of Energy XXI and the accounts of its wholly-owned subsidiaries. All inter-company balances and transactions have been eliminated.

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 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. The most significant financial estimates are based on remaining proved oil and natural gas reserves. Estimates of proved reserves are key components of the Company’s depletion rate for proved oil and natural gas properties and the full cost ceiling test limitation.

See NOTE 18—Supplementary Oil and Gas Information (Unaudited) for more information relating to estimates of proved reserves. Because there are numerous uncertainties inherent in the estimation process, actual results could differ from these 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. The Company’s operations involve the exploration, development and production of oil and natural gas and are entirely located in the United States of America. The Company has a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments.

Cash and Cash Equivalents: The Company considers all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents.

Allowance for Doubtful Accounts: The Company establishes 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, 2006, no allowance for doubtful accounts was necessary.

Oil and Gas Properties: The Company uses 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 oil and natural gas properties. This includes any internal costs that are directly related to 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 natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unproved properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. The Company excludes 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.

General and Administrative Costs: Under the full cost method of accounting, a portion or the Company’s general and administrative expenses that are directly identified with the Company’s acquisition, exploration and development activities are 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 of the Company 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. The Company capitalized general and administrative costs directly related to the Company’s acquisition, exploration and development activities from the period from inception (July 25, 2005) through June 30, 2006 of approximately $1.9 million.

F-9

Capitalized Interest: Interest is capitalized as part of the cost of acquiring assets. Oil and natural gas investments in 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 the Company’s 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 Evaluated Properties Pool, the associated capitalized interest is also transferred. For the period from inception (July 25, 2005) to June 30, 2006, the Company did not capitalize any interest expense.

Ceiling Test: Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by the Securities and Exchange Commission (“SEC”) Regulation S-X Rule 4-10. The ceiling test determines a limit on the carrying value of oil and natural gas properties. The capitalized costs of oil and natural gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, generally using prices in effect at the end of the period held flat for the life of production and including the effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, net of related tax effects, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional DD&A expense. As of June 30, 2006, the Company’s oil and natural gas properties did not exceed the ceiling test limit.

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.

Asset Retirement Obligations: The Company accounts for costs associated with abandoning platforms, wells and other facilities, in accordance with SFAS No. 143 Accounting for Asset Retirement Obligations (“SFAS No. 143”). Obligations associated with abandoning long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has acquired and constructed. The asset retirement obligations are recorded at fair value and accretion expense increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost included in the depreciable base of oil and natural gas properties.

Derivative Instruments: The Company utilizes derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements 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 (“SFAS No. 133”), as amended. Gains or losses resulting from transactions designated as cash flow hedges are recorded at fair value, and are deferred and recorded in Other Comprehensive Income (“OCI”) as appropriate, until recognized in current earnings in the Company’s 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 current earnings.

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

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 the Company 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.

Unrealized gains and losses attributable to ineffectiveness of derivative instruments that receive cash flow hedge accounting treatment, and unrealized and realized gains and losses on derivative instruments that were undertaken to manage the price risk of the Company’s production but do not receive cash flow hedge accounting treatment are excluded from oil and natural gas revenues and included as a separate line in the statement of income.

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The Company also utilizes financial instruments to mitigate the risk of earnings loss due to changes in market interest rates. Such instruments are designated as hedges and accounted for in accordance with SFAS 133.

Revenue Recognition: The Company recognizes oil and natural gas revenue under the entitlement method of accounting. Under the entitlement method, revenue is recognized, based on the Company’s net interest in the well, when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline or a tanker lifting has occurred.

Income Taxes: The Company accounts 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, the Company 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.

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

Accounting for Fair Value Measurements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157 Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“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 SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities using the transaction price in accordance with the guidance in footnote 3 of Issue 02-3 prior to initial application of SFAS No. 157. The Company is 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 inCurrent 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 FASB Statement No. 154, Accounting Changes and Error Corrections, changes in accounting policy generally are accounted for using retrospective application. The adoption of SAB 108 will not have a material impact on the consolidated financial statements of the Company.

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 FASB Statement No. 109 Accounting for Income Taxes (“SFAS 109”). 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. The Company believes that FIN 48 may have an impact on the Company’s 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. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company adopted FIN 48 on July 1, 2006. FIN 48 did not have a material impact on the Company’s consolidated financial statements when adopted.

Accounting Changes and Error Corrections

In May 2005, the FASB issued SFAS No. 154 Accounting Changes and Error Corrections (“SFAS No. 154”), which is a replacement of APB Opinion No. 20 Accounting Changes (“APB 20”), and SFAS No. 3 Reporting Accounting Changes in Interim Financial Statements (“SFAS No. 3”). SFAS No. 154 applies to all voluntary changes in accounting principle, and changes the requirements for accounting for and reporting of a change in accounting principle. The provisions of SFAS 154 will have an impact on the Company’s financial statements in the future should there be voluntary changes in accounting principles. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company adopted SFAS No. 154 on July 1, 2006.

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NOTE 2—OIL AND NATURAL GAS PROPERTIES AND OTHER PROPERTY AND EQUIPMENT

Net capitalized costs related to the Company’s oil and natural gas producing activities and its other property and equipment are as follows (in thousands):

Proved oil and natural gas properties	$	417,237
Accumulated depreciation, depletion, and amortization		(20,225	)
Net proved oil and natural gas properties		397,012
Unproved oil and natural gas properties		50,840
Net oil and natural gas properties	$	447,852
Other property and equipment		1,701
Accumulated depreciation		(132	)
Net other property and equipment	$	1,569
NET PROPERTY AND EQUIPMENT	$	449,421

NOTE 3—ACQUISITION

On April 4, 2006, the Company completed the acquisition of the Oil and Gas Assets which included the purchase of membership interests and limited partner interests including assumed assets and liabilities. The acquisition of the Oil and Gas Assets was accounted for as a business combination under the purchase method of accounted where the consideration was allocated to the assets acquired and liabilities assumed in accordance with SFAS No. 141 Business Combinations. The Oil and Gas Assets represent interests in oil and natural gas production properties and undeveloped acreage in approximately 34 onshore and offshore fields. Four major fields acquired: South Timbalier 21, Vermilion 120, Southwest Speaks, and Main Pass 74 comprise approximately 80% of the proved reserves acquired from Marlin. Total cash consideration of approximately $448.4 million, including acquisition costs of $1.6 million, 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 Company, as part of the post closing settlement with Marlin, is due approximately $14.1 million. 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	)

The Oil and Gas Assets the Company acquired from Marlin were damaged by hurricanes Katrina and Rita but were covered in part by insurance. From the date of the acquisition of the Oil and Gas Assets through June 30, 2006, the Company has spent $32.2 million on inspections, repairs, debris removal, and the drilling of replacement wells. The insurance coverage is an indemnity program that provides for reimbursement after funds are expended. Of the amount spent, the Company believes that $23.5 million is eligible for reimbursement and has recorded this amount as insurance receivable. The $8.7 million difference between the cost of repairs and the expected insurance settlement has been capitalized as oil and gas properties as they are considered development cost. These costs included the costs of platforms and well equipment and construction and installation of production facilities. As of June 30, 2006 the Company has recognized $39.8 million of insurance receivable, which includes $26.6 million acquired from Marlin, $23.5 million recognized since the acquisition less $10.3 million of cash proceeds received from the insurance company.

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NOTE 4—LONG-TERM DEBT

First Lien Revolver: Through EGC, the Company has a $300 million first lien revolver of which as of June 30, 2006, $145 million was committed to by a group of banks, and $122.5 million was outstanding and none was available (See NOTE 16 for modifications since June 30). $117.5 million was outstanding as a loan while $5 million was outstanding in the form of a letter of credit. The revolver is secured by all of the oil and natural gas reserves and other assets owned by EGC. The first lien revolver is subject to early re-determinations, as determined by the agent, made semiannually based upon their assessment of the value of the reserves as determined by a reserve report. Re-determination is January 1 and July 1 of each year. Between re-determinations, the availability under the borrowing base currently declines by $7.5 million per month. Borrowings under the first lien revolver 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 25 to 100 basis; or 2) as LIBOR plus 125 to 200 basis points depending upon the percentage of the total availability drawn at any point in time (the “LIBOR Rate”), at the Company’s option on conversion dates. As of June 30, 2006, EGC had outstanding approximately $9.5 million and $108 million at the Base Rate and LIBOR Rate, respectively. The Base Rate and LIBOR Rate were 9.25% and 7.19% as of June 30, 2006, respectively.

The first lien revolver contains certain covenants, including a required maximum total leverage ratio of 3.5 to 1.0, a required minimum interest coverage ratio of 3.0 to 1.0, and the minimum current ratio of 1.0 to 1.0. At June 30, 2006 the Company was in compliance with all covenants under the first lien revolver. In addition to the financial covenants, the first lien revolver contains 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.

Second Lien Facility: Through EGC, the Company has a $75 million second lien facility of which $75 million was outstanding as of June 30, 2006. The second lien facility is secured by a second lien on all of the oil and natural gas reserves and other assets owned by EGC. Principal payments on the second lien facility are due each April at 1% of the unpaid principal balance; with the unpaid balance maturing on April 2, 2010. 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 500 basis points (the “LIBOR Rate”), at the Company’s option on conversion dates. The second lien facility is callable at the option of the Company at a 1% premium in the first year with no premium payable thereafter. As of June 30, 2006, EGC had outstanding $75 million at the LIBOR Rate. The LIBOR Rate was 10.06% as of June 30, 2006. As more fully described in NOTE 16, the second lien facility was modified in July, 2006.

The second lien facility contains certain covenants, including a required maximum total leverage ratio of 4.0 to 1.0, a required minimum interest coverage ratio of 2.75 to 1.0, a minimum current ration of 1.0 to 1.0, and a requirement to maintain a ratio of the net present value of the future net revenues of proved reserves, discounted at 10% per annum, to total debt of 1.5 to 1.0. At June 30, 2006 the Company was in compliance with all covenants under the second lien facility.

Note Purchase Agreement: Through US Holdings, the Company entered into a notes purchase agreement with Satellite dated March 2, 2006 whereby US Holdings agreed to sell $17.5 million aggregate principal amount of its 6.5% senior notes due May 11, 2006 for a purchase price of $14.15 million. The note purchase agreement was paid in full on April 4, 2006, including interest expense of $3.5 million.

Put Premium Financing: In conjunction with the Company’s hedging program, the Company financed certain purchased put premiums with the applicable counterparty. The total cost of the financed put premiums was $18.4 million with the cost of financing embedded in the price of the put. The Company recorded the cost of these financed put premiums at their discounted value using an implicit interest rate of 8.5%. The total interest implicit in these contracts is approximately $1.4 million. Included in interest expense for the period from inception (July 25, 2005) through June 30, 2006 is $162,743 related to the financing of the put premiums.

Future maturities of long-term debt are as follows (in thousands):

Year Ending June 30,
2007	$	9,584
2008		6,318
2009		120,554
2010		73,192
2011		—
Thereafter		—
Total		209,648
Less current portion		(9,584	)
Long-term debt	$	200,064

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NOTE 5—ASSET RETIREMENT OBLIGATIONS

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

Carrying amount of ARO at July 25, 2005 (inception)	$	—
ARO acquired		36,595
Accretion expense		738
ARO incurred due to drilling activities		511
Carrying amount of ARO at June 30, 2006	$	37,844

NOTE 6—DERIVATIVE FINANCIAL INSTRUMENTS

The Company enters into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. The Company uses 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 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 the Company 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 the Company if the settlement price for a settlement period is below the hedged price for the transaction, and the Company is 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 the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar.

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 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, the Company recognized income of $119,736 related to the net price ineffectiveness of its 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, 2006, the Company had the following hedge contracts outstanding:

	Crude Oil						Natural Gas
Period	Daily Volume (MBbls)		Contract Price		June 30, 2006 Fair Value (Gain) Loss		Daily Volume (MMBtu)		Contract Price		June 30, 2006 Fair Value (Gain) Loss			Total
Puts(1)
July 2006 -June 2007		588	$	60 - 65	$	1,879		10,770	$	8.00	$	(931	)	$	948
July 2007 -June 2008		141		60		101		6,969		8.00		(92	)		9
July 2008 -June 2009		53		60		38		2,680		8.00		(40	)		(2	)
						2,018						(1,063	)		955
Swaps
July 2006 -June 2007		814	$	69.08 - 74.50		2,231		2,696	$	6.72 - 9.84		(880	)		1,351
July 2007 -June 2008		535		69.08 - 72.00		1,606		2,468		9.00 - 9.84		(633	)		973
July 2008 -June 2009		459		69.08 - 71.96		604		1,630		9.00 - 9.39		(429	)		175
July 2009 -June 2010		227		69.24 - 71.06		43		600		9.02		(213	)		(170	)
						4,484						(2,155	)		2,329
Collars
July 2006 -June 2007		243	$	60 - 78		665		1,250	$	8.00 - 11.10		(144	)		521
July 2007 -June 2008		278		60 - 78		761		1,120		8.00 - 11.10		(129	)		632
July 2008 -June 2009		106		60 - 78		291		430		8.00 - 11.10		(50	)		241
						1,717						(323	)		1,394
Net (gain) loss on derivatives					$	8,219					$	(3,541	)	$	4,678

(1) Included in natural gas puts are 8,260 MMBtus, 6,390 MMBtus and 2,450 MMBtus of $6 to $8 put spreads for the years ended June 30, 2007, 2008 and 2009, respectively.

The Company has reviewed the financial strength of its hedge counterparties and believes the credit risk to be minimal. At June 30, 2006, the Company had no deposits for collateral with its counterparties.

The following table sets forth the results of third party hedging for the period from inception (July 25, 2005) through June 30, 2006 (dollars in thousands):

	Crude Oil (MBbls)			Natural Gas (MMBtus)
Quantity settled		314			1,331
Increase (decrease) in revenues	$	(695	)	$	2,122

On June 26, 2006, the Company 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% to 5.75%. At June 30, 2006, the Company had deferred $126,442, net of tax, in gains in OCI related to this instrument.

The following table reconciles the changes in accumulated other comprehensive income (loss) for the period from inception (July 25, 2005) through June 30, 2006 (in thousands):

Accumulated other comprehensive income (loss)—inception (July 25, 2005)	$	—
Hedging activities:
Change in fair value of crude oil and natural gas hedging positions		(4,678	)
Change in fair value of interest rate hedging position		126
Accumulated other comprehensive income (loss) at June 30, 2006	$	(4,552	)

NOTE 7—INCOME TAXES

The components of the Company’s income tax provision are as follows (in thousands):

Current	$	913
Deferred		814
Tax provision	$	1,727

F-14

The following is a reconciliation of statutory income tax expense to the Company’s income tax provision (in thousands):

Income before income taxes	$	8,669
Statutory rate		35	%
Income tax expense computed at statutory rate		3,034
Reconciling items:
State income taxes, net of federal tax benefit		50
Non taxable foreign income		(1,357	)
Tax provision	$	1,727

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 the Company’s deferred taxes are detailed in the table below (in thousands):

Deferred tax assets:
Derivative instruments	$	2,519
Oil and natural gas property		1,310
Accretion of asset retirement obligation		258
Employee benefit plans		104
Total deferred tax assets		4,191
Deferred tax liabilities:
Other property and equipment		2,411
Derivative instruments		143
Total deferred tax liabilities		2,554
Net deferred tax asset	$	1,637
Reflected in the accompanying balance sheet as:
Non-current deferred tax asset	$	1,780
Current deferred tax liability	$	(143	)

NOTE 8—STOCKHOLDERS’ EQUITY

Common Stock

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

Preferred Stock

The Company’s bye-laws authorize the issuance of 2,500,000 shares of preferred stock. The Company’s 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. The Company had not issued preferred stock as of June 30, 2006.

Warrants

The Company 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 the Company sends the notice of redemption and the weekly trading volume of the Company’s common shares has exceeded 800,000 for each of the two calendar weeks before the Company sends 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 the Company calls the warrants. The warrants will expire October 20, 2009. On June 7, 2006, the Company 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, the Company 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. See NOTE 16 for further information with respect to the exercise of the warrants.

F-15

Unit Purchase Option

As part of the placement on the AIM, the Company 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. 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.

NOTE 9—SUPPLEMENTAL CASH FLOW INFORMATION

The following represents the Company’s supplemental cash flow information (in thousands):

Cash paid for interest	$	4,760
Cash paid for income taxes	$	—

The following represents the Company’s non-cash investing and financing activities (in thousands):

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	$	5,986
Additions to property and equipment by recognizing asset retirement obligations	$	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 10—EMPLOYEE BENEFIT PLANS

Participation Share Program: The Company has adopted a Participating Share Program as an incentive and retention program for its employees. Participation shares (or “Phantom Stock”) are issued from time to time at a value equal to the Company’s share price at the time of issue. The Phantom Stock vest equally over a three-year period. When vesting occurs, the Company pays the employee an amount equal to the then current share price times the number of restricted stock units that have vested, plus the cumulative value of dividends applicable to the Company’s stock. At the Company’s sole discretion, at the time the Phantom Stock vest, the Company has the ability to offer the employee to accept shares in lieu of cash. Upon a change in control of the Company, all outstanding Phantom Stock become immediately vested and payable.

As of June 30, 2006, the Company had issued 745,000 shares of Participation Shares and recognized expense of $138,304 and capitalized $82,699 in oil and natural gas properties. A liability has been recognized in the amount of $221,003 in Other liabilities in the accompanying Consolidated Balance Sheet. The amount of the liability will be remeasured to fair value as of each reporting date. No Phantom Stock has vested as of June 30, 2006.

Defined Contribution Plans: The Company’s employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions based upon 10% of annual salaries. The Company also sponsors a qualified 401(k) Plan. The cost to the Company under these plans was approximately $104,828.

NOTE 11—RELATED PARTY TRANSACTIONS

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

F-16

The Company has entered into employment agreements with each of Messrs. Schiller, Weyel, and Griffin, who serve as the Company’s Chief Executive Officer and Chairman of its 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 the Company 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 the Company gives written notice within 90 days prior to the end of the term that such party desires not to renew the employment agreement.

NOTE 12—EARNINGS PER SHARE

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

Net Income	$	6,942
Weighted average shares outstanding for basic EPS		49,839,179
Add dilutive securities: warrants		8,635,592
Weighted average shares outstanding for diluted EPS		58,474,771
Earnings per share—basic	$	0.14
Earnings per share—diluted	$	0.12

NOTE 13—COMMITMENTS AND CONTINGENCIES

Litigation: The Company is a party to litigation in the normal course of business. While the outcome of litigation against the Company cannot be predicted with certainty, management believes that the effect on its financial condition, results of operations and cash flows, if any, will not be material.

Lease Commitments: The Company has a non-cancelable operating lease for office space that expires on July 31, 2013. Future minimum lease commitments as of June 30, 2006 under the operating leases are as follows (in thousands):

Year Ending June 30,
2007	$	638
2008		726
2009		726
2010		726
2011		726
Thereafter		736
Total	$	4,278

Rent expense for the period from inception (July 25, 2005) through June 30, 2006 was approximately $76,000.

Letters of Credit and Performance Bonds: The Company had $5.3 million in letters of credit and $38.8 million of performance bonds outstanding as of June 30, 2006.

Drilling Rig Commitments: In June 2006, the Company entered into a 90 day agreement, commencing on August 31, 2006, to secure a drilling rig for a total commitment of $20.7 million.

NOTE 14—CONCENTRATIONS OF CREDIT RISK

Major Customers: The Company’s production is sold on month-to-month contracts at prevailing prices. The following table identifies customers from whom the Company derived 10% or more of its net oil and natural gas revenues during the period from inception (July 25, 2005) through June 30, 2006. Based on the availability of other customers, the Company does not believe the loss of any of these customers would have a significant effect on its operations or financial condition.

F-17

Customer	Percent of Total Revenue
Chevron, USA		57	%
Louis Dreyfus Energy Services, LP		14	%

Accounts Receivable: Substantially all of the Company’s 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 the Company’s 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, the Company does not expect that termination of sales to any of its current purchasers would have a material adverse effect on its ability to find replacement purchasers and to sell its production at favorable market prices.

Derivative Instruments: Derivative instruments also expose the Company to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. The Company believes that its 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 its hedging activities reduces volatility in its reported results of operations, financial position and cash flows from period to period and lowers its overall business risk.

Cash and Cash Equivalents: The Company is subject to concentrations of credit risk with respect to its cash and cash equivalents, which the Company attempts to minimize by maintaining its 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 15—FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company includes fair value information in the notes to the consolidated financial statements when the fair value of its financial instruments is different from the book value. The Company believes that the carrying value of its 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.

NOTE 16—SUBSEQUENT EVENTS

Acquisition: On June 7, 2006, EGC 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”). The Company 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 with 35 producing wells and approximately 76,000 net acres. Approximately 91% of the proved reserves are natural gas.

EGC closed the acquisition on July 28, 2006 and at the same time entered into a 50/50 exploration agreement with the seller for 24 months covering an area of mutual interest in South Louisiana. In addition, the Company entered into a joint development agreement with the seller which includes the area around Lake Salvador. The Company’s cash cost of the acquisition was approximately $308 million for the reserves and the Company agreed to provide up to a $31 million carried interest in future wells to be drilled.

The Company’s obligation to fund the carried interest is limited to no more than $4 million per month. The Company anticipates that this carried interest will be fully realized within 24 months. In addition, if hydrocarbon production from one of the properties acquired exceeds 34 billion cubic feet equivalent (BCFE), a level above the proved reserves assumed by the company 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.

Early Warrant Exercise: As part of the funding of the Castex Acquisition, on June 7, 2006, the Company temporarily reduced the exercise price on its warrants from $5 a share to $4 per share. As of the end of the discounted warrant exercise period (July 10, 2006), 21,410,128 warrants were exercised (18,145,129 as of June 30, 2006), resulting in total cash inflow of approximately $ 85.6 million to the Company. Upon completion of a warrant exercise, there were 83,910,128 shares of common stock and 78,589,872 warrants outstanding.

Financing: 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 an expansion of existing credit facilities by $340 million. The credit facilities expansion represents an increase in the second lien facility, led by BNP Paribas, from $75 million to $300 million with a further extension to $325 million available depending upon demand during syndication and increased availability under the first lien revolver, led by The Royal Bank of Scotland, from $145 million to $260 million. At closing, the Company had $300 million of the second lien facility drawn plus an additional $124.5 million under the first lien facility utilized resulting in total indebtedness of $424.5 million plus a $5 million letter of credit, leaving $130.5 million of availability under the Company’s revised credit facilities to fund future growth and operations. Borrowings under the first lien revolver 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 25 to 100 basis points; or 2) as LIBOR plus 125 to 200 basis points depending upon the percentage of the total availability drawn at any point in time (the “LIBOR Rate”), at the Company’s option on conversion dates. 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.

F-18

The syndication of the second lien facility was oversubscribed and on September 1, 2006, the second lien facility was increased to $325 million. The net amount of this extension, after fees, was used to reduce outstanding indebtedness under the first lien revolver. As of the date of this report, the Company had total debt under the first lien revolver and second lien facility of $456.9 million comprised of $131.9 million on the first lien revolver and $325 million on the second lien facility. Additionally, the Company had a further $93 million available for borrowing under the first lien revolver.

Drilling Rig Commitments: The Company, subsequent to June 30, 2006, entered into three agreements ranging from 90 days to one year to secure drilling rigs. Total commitments under the contacts are approximately $44.7 million.

NOTE 17—PRO FORMA INFORMATION (UNAUDITED)

The following summarizes the unaudited pro forma financial information for the year ended June 30, 2006 assuming the Oil and Gas Assets acquired from Marlin described in NOTE 3 occurred as of July 1, 2005. These unaudited pro forma financial results have been prepared for informational purposes only. These unaudited pro forma financial results may not be indicative of the results that would have occurred if the Company had completed the acquisitions as of July 1, 2005 or the results that will be attained in the future. (in thousands, except per share data)

Oil and natural gas revenues	$	157,110
Net income	$	5,006
Net income per share—basic	$	0.06
Net income per share—diluted	$	0.06

NOTE 18—SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)

The following information concerning the Company’s oil and natural gas operations has been provided pursuant to SFAS No. 69 Disclosures about Oil and Gas Producing Activities. The Company’s oil and natural gas producing activities are conducted offshore in federal and state waters of the Gulf of Mexico and onshore in Texas and Louisiana.

Capitalized Costs of Oil and Natural Gas Properties (in thousands)

Unproved oil and natural gas properties, not subject to amortization	$	50,840
Proved oil and natural gas properties subject to amortization		417,237
Capitalized costs		468,077
Accumulated depreciation, depletion and amortization		(20,225	)
Net capitalized costs	$	447,852

Capitalized Costs Incurred (in thousands)

Costs incurred for oil and natural gas acquisition, exploration, development are summarized below. Costs incurred for the period from inception (July 25, 2005) through June 30, 2006 include general and administrative costs related to acquisition, exploration and development of oil and natural gas properties of $1.9 million. There was no interest expensed capitalized during this period.

Acquisition of properties:
Unevaluated	$	50,840
Proved		393,087
Exploration costs		—
Development costs		24,150
Total costs incurred	$	468,077

Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the computation of the standardized measure of discounted future net cash flows relating to proved reserves and the changes in such cash flows in accordance with SFAS No. 69. The standardized measure is the estimated excess future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs, estimated future income taxes and a discount factor. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on period-end prices and any fixed and determinable future price changes provided by contractual arrangements in existence at year end. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. Estimated future income tax expenses are computed using the appropriate period-end statutory tax rates. A discount rate of 10% is applied to the annual future net cash flows.

The methodology and assumptions used in calculating the standardized measure are those required by SFAS No. 69. The standardized measure is not intended to be representative of the fair market value of the proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended. Average prices per Bbl and Mcf of oil and natural gas, respectively, used in making the present value and standardized measure determination as of June 30, 2006, was $70.75 and $6.09, respectively.

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

Future cash inflows	$	1,356,910
Future costs:
Production costs		(321,502	)
Development costs		(231,692	)
Future income tax expense		(144,669	)
10% annual discount for estimating timing of cash flows		(184,549	)
Standardized measure of discounted future net cash flows	$	474,498

As of June 30, 2006, the Company’s standardized measure of discounted future net cash flows includes estimated future development costs for the Company’s proved undeveloped reserves of $148.3 million.

Changes in standardized measure from inception (July 25, 2005) through June 30, 2006 (in thousands):

Standardized measure, inception (July 25, 2005)	$	—
Sales and transfers of oil and natural gas produced net of production costs		(37,126	)
Net changes in price and production costs		(22,732	)
Extensions, discoveries and improved recovery, less related costs		—
Revisions of previous quantity estimates		19,294
Accretion of discount		—
Net change in income taxes		(103,941	)
Purchases (sales) of minerals in place		620,040
Development costs incurred during the period		23,639
Changes in estimated future development		(24,676	)
Standardized measure, June 30, 2006	$	474,498

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of the Company’s oil and natural gas properties located entirely within the United States of America, are based on evaluations prepared by the Company’s 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 natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

F-19

Estimated quantities of proved domestic oil and natural 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)
Proved developed and undeveloped reserves at inception (July 25, 2005)		—			—
Purchases of minerals in place—April 4, 2006		14,160			66,674
Extensions and discoveries		—			—
Revisions to previous estimates		106			436
Production—April 4, 2006 through June 30, 2006		(446	)		(2,459	)
Proved developed and undeveloped reserves at June 30, 2006		13,820			64,651
Proved developed reserves at June 30, 2006		8,922			42,246

F-20

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2007

F-21

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	March 31, 2007		June 30, 2006
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10,177	$	62,389
Accounts receivable
Oil and natural gas sales		40,818		19,325
Joint interest billings		14,961		11,173
Acquisition		—		14,070
Stock subscription		—		7,326
Insurance		109		39,801
Prepaid expenses and other current assets		48,701		9,200
Royalty deposit		2,175		2,175
Derivative financial instruments		15,543		7,752
TOTAL CURRENT ASSETS		132,484		173,211
PROPERTY AND EQUIPMENT, net of accumulated depreciation, depletion, and amortization (“DD&A”)
Oil and natural gas properties—full cost method of accounting, including $199,780 and $50,840 of unproved oil and natural gas properties as of March 31, 2007 and June 30, 2006, respectively, and net of accumulated DD&A of $107,594 and $20,225 as of March 31, 2007 and June 30, 2006, respectively.		925,906		447,852
Other property and equipment, net of accumulated depreciation of $818 and $132 as of March 31, 2007 and June 30, 2006, respectively.		3,036		1,569
TOTAL PROPERTY AND EQUIPMENT, NET		928,942		449,421
Deposit and acquisition costs		—		10,025
Derivative financial instruments		4,508		5,856
Deferred income taxes		—		1,780
Debt issuance costs, net of accumulated amortization of $1,223 and $306, as of March 31, 2007 and June 30, 2006, respectively		2,434		3,678
TOTAL ASSETS	$	1,068,368	$	643,971

See accompanying Notes to Consolidated Financial Statements

F-22

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED BALANCE SHEETS (Continued)

(In Thousands, except share information)

	March 31, 2007		June 30, 2006
	(Unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	47,119	$	23,281
Advances from joint interest partners		6,295		6,211
Accrued liabilities		8,327		11,463
Income and franchise taxes payable		1,512		913
Deferred income taxes		2,287		143
Derivative financial instruments		4,073		948
Current maturities of long-term debt		9,634		9,584
TOTAL CURRENT LIABILITIES		79,247		52,543
Long-term debt, less current maturities		532,712		200,064
Deferred income taxes		12,628		—
Asset retirement obligations		45,981		37,844
Derivative financial instruments		—		590
Other liabilities		1,530		221
TOTAL LIABILITIES		672,098		291,262
COMMITMENTS AND CONTINGENCIES (NOTE 10)
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value, 2,500,000 shares authorized and no shares issued at March 31, 2007 and June 30, 2006		—		—
Common stock, $0.001 par value, 396,500,624 shares authorized and 84,049,115 and 80,645,129 issued and outstanding at March 31, 2007 and June 30, 2006, respectively		84		81
Additional paid-in capital		362,334		350,238
Retained earnings		28,864		6,942
Accumulated other comprehensive income (loss), net of tax expense of $2,725 as of March 31, 2007 and net of tax benefit of $2,541 as of June 30, 2006.		4,988		(4,552	)
TOTAL STOCKHOLDERS’ EQUITY		396,270		352,709
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,068,368	$	643,971

See accompanying Notes to Consolidated Financial Statements

F-23

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, except per share information)

(Unaudited)

	Three Months Ended March 31,						Nine Months Ended March 31, 2007			Period from Inception July 25, 2005 Through March 31, 2006
	2007			2006
REVENUES
Oil sales	$	42,776		$	—		$	121,882		$	—
Natural gas sales		34,832			—			100,686			—
TOTAL REVENUES		77,608			—			222,568			—
COSTS AND EXPENSES
Lease operating expense		11,485			—			33,638			—
Production taxes and transportation		1,691			—			2,909			—
Depreciation, depletion and amortization		28,600			21			88,055			40
Accretion of asset retirement obligation		877			—			2,619			—
General and administrative expense		10,599			1,204			26,505			1,755
Gain on derivative financial instruments		(1,552	)		—			(3,110	)		—
TOTAL COSTS AND EXPENSES		51,700			1,225			150,616			1,795
OPERATING INCOME (LOSS)		25,908			(1,225	)		71,952			(1,795	)
OTHER INCOME (EXPENSE)
Interest income		307			2,798			1,599			4,709
Interest expense		(12,646	)		(1,506	)		(39,653	)		(1,506	)
TOTAL OTHER INCOME (EXPENSE)		(12,339	)		1,292			(38,054	)		3,203
INCOME BEFORE INCOME TAXES		13,569			67			33,898			1,408
PROVISION FOR INCOME TAXES		3,988			—			11,976			—
NET INCOME	$	9,581		$	67		$	21,922		$	1,408
EARNINGS PER SHARE
Basic	$	0.11		$	0.00		$	0.26		$	0.03
Diluted	$	0.11		$	0.00		$	0.26		$	0.03
WEIGHTED AVERAGE NUMBER OF COMMON STOCK OUTSTANDING
Basic		84,049			62,500			83,893			42,821
Diluted		84,049			62,500			83,893			42,821

See accompanying Notes to Consolidated Financial Statements

F-24

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In Thousands)

(Unaudited)

	Shares		Amount		Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance, June 30, 2006		80,645	$	81	$	350,238		$	6,942	$	(4,552	)	$	352,709
Common stock issued		3,404		3		13,164			—		—			13,167
Warrants repurchased		—		—		(1,068	)		—		—			(1,068	)
Comprehensive income:
Net income		—		—		—			21,922		—			21,922
Unrealized gain on derivative financial instruments, net of tax		—		—		—			—		9,540			9,540
Total comprehensive income														31,462
Balance, March 31, 2007		84,049	$	84	$	362,334		$	28,864	$	4,988		$	396,270

See accompanying Notes to Consolidated Financial Statements

F-25

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Nine Months Ended March 31, 2007			Period from Inception July 25, 2005 Through March 31, 2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	21,922		$	1,408
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Deferred income tax expense		3,954			—
Unrealized loss on derivative financial instruments		18,527			—
Accretion of asset retirement obligations		2,619			—
Depletion, depreciation, and amortization		88,055			40
Write-off of debt issuance costs-net		5,998			1,415
Changes in operating assets and liabilities
Accounts receivable		35,807			—
Prepaid expenses and other current assets		(39,501	)		(4,230	)
Accounts payable and other liabilities		21,385			998
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		158,766			(369	)
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition		(302,481	)		(10,160	)
Capital expenditures		(250,951	)		(384	)
Proceeds from the sale of oil and natural gas properties		1,400			—
Other		1,333			—
NET CASH USED IN INVESTING ACTIVITIES		(550,699	)		(10,544	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of common stock		13,167			300,026
Proceeds from long-term debt		364,000			14,150
Payments on long-term debt		(24,625	)		—
Payments on put financing		(7,030	)		—
Stock issuance costs		—			(21,712	)
Debt issuance costs		(4,754	)		—
Other		(1,037	)		—
NET CASH PROVIDED BY FINANCING ACTIVITIES		339,721			292,464
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(52,212	)		281,551
CASH AND CASH EQUIVALENTS, beginning of period		62,389			—
CASH AND CASH EQUIVALENTS, end of period	$	10,177		$	281,551

See accompanying Notes to Consolidated Financial Statements

F-26

ENERGY XXI (BERMUDA) LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2007

(UNAUDITED)

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. The Company is 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.

Revenue Recognition. The Company recognizes oil and natural gas revenue under the entitlement method of accounting. Under the entitlement method, revenue is recorded when title passes based on the Company’s net interest. The Company records its entitled share of revenues based on entitled volumes and contracted sales prices.

Interim Financial Statements. The consolidated financial statements for the periods presented herein are unaudited and do not contain all information required by generally accepted accounting principles (“GAAP”) to be included in a full set of financial statements. In the opinion of management, all material adjustments necessary to present fairly the results of operations have been included. All such adjustments are of a normal, recurring nature. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year. These unaudited consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements included in the Company’s annual report for the period ended June 30, 2006.

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 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. The most significant financial estimates are based on remaining proved oil and natural gas reserves. Estimates of proved reserves are key components of the Company’s depletion rate for proved oil and natural gas properties and the full cost ceiling test limitation.

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. The Company’s operations involve the exploration, development and production of oil and natural gas and are entirely located in the United States of America. The Company has a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments.

General and Administrative Costs. Under the full cost method of accounting, a portion or the Company’s general and administrative expenses that are directly identified with the Company’s acquisition, exploration and development activities are 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 of the Company 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. The Company’s capitalized general and administrative costs directly related to the Company’s acquisition, exploration and development activities for the quarter and nine months ended March 31, 2007 were $1.7 million and $4.1 million, respectively.

Principles of Consolidation. The Company’s consolidated financial statements include the accounts of Energy XXI and the accounts of its wholly-owned subsidiaries. All inter-company balances and transactions have been eliminated. The consolidated financial statements include certain reclassifications that were made to conform to current period presentation.

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

F-27

Accounting for Stock-based Compensation

In December 2004, the FASB issued SFAS 123(R), “Share-Based Payment,” (“SFAS 123(R)”), which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS 123(R) is effective for public companies for annual periods beginning after December 15, 2005, supersedes APB Opinion 25, Accounting for Stock Issued to Employees, and amends SFAS 95, Statement of Cash Flows. SFAS 123(R) requires all share-based payments to employees including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro-forma disclosure is no longer an alternative. The Company adopted SFAS 123(R) on July 1, 2006 and its adoption did not have a material impact on the Company’s consolidated financial statements.

Accounting for Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157 Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“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 SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities using the transaction price in accordance with the guidance in footnote 3 of Issue 02-3 prior to initial application of SFAS No. 157. The adoption of SFAS No. 157 is not expected to have a material impact on the consolidated financial statements of the Company.

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 inCurrent 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 FASB Statement No. 154, Accounting Changes and Error Corrections, changes in accounting policy generally are accounted for using retrospective application. The adoption of SAB 108 did not have a material impact on the consolidated financial statements of the Company.

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 FASB Statement No. 109 Accounting for Income Taxes (“SFAS 109”). 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. The Company believes that FIN 48 may have an impact on the Company’s 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. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company will adopt FIN 48 effective July 1, 2007. The Company is in the process of determining the effect, if any, the adoption of FIN 48 will have on its 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 FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.

F-28

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. The Company is in the process of determining the effect, if any, the adoption of this FSP will have on its consolidated financial statements.

NOTE 2—ACQUISITIONS

On June 7, 2006, the Company 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”). The Company 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 with 35 producing wells and approximately 76,000 net acres. Approximately 91% of the proved reserves are natural gas.

The Company 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, the Company entered into a joint development agreement with one of the Sellers that includes the area around Lake Salvador (the “Joint Development Agreement”). The Company’s cash cost of the acquisition was approximately $311.2 million for the reserves and the Company agreed to provide up to a $31 million carried interest in future wells to be drilled, of which $8.1 million remains as of March 31, 2007.

The Company’s obligation to fund the carried interest is limited to no more than $4 million per month. The Company anticipates that this carried interest will be fully realized within 24 months. In addition, if hydrocarbon production from one of the properties acquired exceeds 34 billion cubic feet equivalent (BCFE), a level above the proved reserves assumed by the Company 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.

Lake Salvador Joint Development Agreement: The Joint Development Agreement covers and 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. The Company and the Seller party to the Exploration Agreement each have the optional right to participate for a 50% 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”).

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. The Company acquired rights to approximately 1,000 square miles of 3D seismic data within the Lake Salvador AMI and has the commitment to bear 50% of an estimated $11 million seismic acquisition cost. As of March 31, 2007, approximately $0.1 million in committed seismic costs remained as an obligation of the Company.

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 acquired by Company from the Sellers in the Castex Acquisition are excluded from the provisions of the Exploration AMI. The Company and the two Sellers party to the Exploration Agreement each have the optional right to participate for a 50% 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	$	316,720
Asset retirement obligations		(5,518	)
Cash paid, including acquisition costs of $1,362	$	(311,202	)

F-29

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

On February 21, 2006, the Company entered into a definitive agreement with Marlin Energy, L.L.C. (“Marlin”) to acquire 100% 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	)

On January 26, 2007, EGC entered into a Participation Agreement (the “Participation Agreement”) with Centurion Exploration Company (“Centurion”). Pursuant to the Participation Agreement, EGC paid a consideration of $2.3 million to Centurion to acquire fifty percent (50%) interest in each of seven identified drilling prospects located on a 100,000 acre Area of Mutual Interest in southeastern Louisiana. Under the Participation Agreement, EGC has the option to and anticipates drilling six to eight exploratory wells on these prospects over the next twelve months. EGC will bear 66.67% of the costs of the initial well on each prospect it elects to drill, which are currently anticipated to total approximately $40 million for the six to eight exploratory wells. 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 set forth in the Participation Agreement will result in forfeiture of the interest acquired and the initial consideration paid, on a prospect by prospect basis. EGC will serve as operator of each project. The first well was spud in March 2007.

NOTE 3—LONG-TERM DEBT

Long-term debt follows (in thousands):

	March 31, 2007		June 30, 2006
First lien revolver	$	206,875	$	117,500
Second lien facility		325,000		75,000
Put premium financing		10,026		16,728
Capital lease obligation		445		420
Total debt		542,346		209,648
Less current maturities		9,634		9,584
Total long-term debt	$	532,712	$	200,064

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. The availability of the first lien revolver, led by The Royal Bank of Scotland, was increased from $145 million to $260 million. At closing of the Castex Acquisition, the Company had $300 million of the second lien facility drawn plus $124.5 million under the first lien facility utilized resulting in total indebtedness of $424.5 million plus a $5 million letter of credit, leaving $130.5 million of availability under the Company’s revised credit facilities to fund future growth and operations. Borrowings under the first lien revolver 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 25 to 100 basis points; or 2) as LIBOR plus 125 to 200 basis points depending upon the percentage of the total availability drawn at any point in time (the “LIBOR Rate”), at the Company’s option on conversion dates. The effective interest rate on the first lien revolver as of December 31, 2006 was 7.125%. 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 effective interest rate on the second lien facility as of March 31, 2007 was 10.875%.

F-30

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 matures on April 10, 2010.

In connection with the amendment of the second lien facility, the Company expensed approximately $5.1 million of debt issuance costs. In accordance with EITF 96-19 Debtors Modification or Exchange ofDebt Instruments, if an amendment or modification of a debt instrument is substantial it is considered an extinguishment and the unamortized debt issuance costs of the original instrument and the creditor fees associated with the new debt instrument are expensed. A modification is considered substantial when the present value of the cash flows under the terms of a new debt instrument is at least 10 percent different from the present value of the remaining cash flows under the terms of the original instrument. The Company’s amendment to the second lien facility in September 2006 met this criterion. The $5.1 million included in interest expense consists of $3.9 million in placement fees paid to BNP Paribas in connection with the amendment to the second lien facility and unamortized debt issuance costs of the original second lien facility of approximately $1.2 million.

On March 7, 2007, the Company amended the first lien revolver to reset the borrowing base to $280 million, subject to a $10 million per month reduction in the borrowing base. As of March 31, 2007, the Company had $206.9 million outstanding as loans, a $5 million letter of credit, and unused capacity of $68.1 million. The first lien revolver matures on April 4, 2009.

Total interest expense for the three months ended March 31, 2007, of $12.6 million, consists of $0.3 million of debt issuance costs, interest expense of $11.7 million associated with the first lien revolver and second lien facility, amortization of $0.6 million associated with premium financing and other.

Total interest expense for the nine months ended March 31, 2007, of $39.7 million, consists of $6.0 million amortization of debt issuance costs, interest expense of $32.4 million associated with the first lien revolver and second lien facility and $1.3 million associated with put premium financing and other.

NOTE 4—ASSET RETIREMENT OBLIGATIONS

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

Carrying amount of ARO at July 1, 2006	$	37,844
ARO acquired		5,518
Accretion expense		2,619
Carrying amount of ARO at March 31, 2007	$	45,981

NOTE 5—DERIVATIVE FINANCIAL INSTRUMENTS

The Company enters into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. The Company uses 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 the Company 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 the Company if the settlement price for a settlement period is below the hedged price for the transaction, and the Company is 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 the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is 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 the Company 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.

F-31

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 nine months ended March 31, 2007 resulted in an increase in oil and natural gas sales in the amount of $22.9 million. For the nine months ended March 31, 2007, the Company recognized a loss of approximately $1.1 million related to the net price ineffectiveness of its hedged crude oil and natural gas contracts and a realized gain and an unrealized loss of approximately $8.5 million and $4.3 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

As of March 31, 2007, the Company had the following contracts outstanding:

	Crude Oil							Natural Gas							Total Fair Value Gain (Loss)(2)
Period	Volume (MBbls)		Contract Price		Fair Value Gain (Loss)			Volume (MMBtus)		Contract Price		Fair Value Gain
Puts(1)
April 1, 2007-March 31, 2008		160	$	60	$	(160	)		7,560	$	8.00	$	(458	)	$	(618	)
April 1, 2008-March 31, 2009		83		60		(83	)		4,190		8.00		(87	)		(170	)
						(243	)						(545	)		(788	)
Swaps
April 1, 2007-March 31, 2008		820	$	69.08-72.00		4,763			11,286	$	7.00-9.84		2,912			7,675
April 1, 2008-March 31, 2009		812		69.08-71.96		1,258			6,770		8.95-9.39		1,549			2,807
April 1, 2009-March 31, 2010		489		69.24-71.06		131			3,020		7.00-9.02		321			452
						6,152							4,782			10,934
Collars
April 1, 2007-March 31, 2008		307	$	60-78		(214	)		2,440	$	8.00-11.10		733			519
April 1, 2008-March 31, 2009		166		60-78		(115	)		1,260		8.00-11.10		377			262
						(329	)						1,110			781
Three-Way Collars
April 1, 2007-March 31, 2008		1,018	$	45/65/72.90		(4,087	)		1,820	$	6/8/10		(141	)		(4,2228	)
April 1, 2008-March 31, 2009		268		55/65/72.90		(444	)		1,580		6/8/10		(123	)		(567	)
April 1, 2009-March 31, 2010		59		55/65/72.90		(98	)		1,950		6/8/10		(152	)		(250	)
						(4,629	)						(416	)		(5,045	)
Net gain on derivatives					$	951						$	4,931		$	5,882

(1)Included in natural gas puts are 6,910 MMBtus and 3,840 MMBtus of $6 to $8 put spreads for the years ended March 31, 2008 and 2009, respectively.

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

The Company has reviewed the financial strength of its hedge counterparties and believes the credit risk to be minimal. At March 31, 2007, the Company had no deposits for collateral with its counterparties.

On June 26, 2006, the Company 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% to 5.75%. At March 31, 2007, the Company had deferred $894,000, net of tax benefit, in losses in OCI related to this instrument.

The following table reconciles the changes in accumulated other comprehensive income (loss) for the period from July 1, 2006 through March 31, 2007 (in thousands):

Accumulated other comprehensive loss, net of tax benefit of $2,451—July 1, 2006	$	(4,552	)
Hedging activities:
Change in fair value of crude oil and natural gas hedging positions, net of tax of $5,733		10,560
Change in fair value of interest rate hedging position, net of tax benefit of $556		(1,020	)
Accumulated other comprehensive income, net of tax of $2,725—March 31, 2007	$	4,988

F-32

NOTE 6—SUPPLEMENTAL CASH FLOW INFORMATION

The following represents the Company’s supplemental cash flow information for the nine months ended March 31, 2007 (in thousands):

Cash paid for interest	$	33,501
Cash paid for income taxes	$	2,400

NOTE 7—EMPLOYEE BENEFIT PLANS

Participation Share Program. The Company has adopted a Participating Share Program as an incentive and retention program for its employees. Participation shares (or “Phantom Stock”) are issued from time to time at a value equal to the Company’s share price at the time of issue. The Phantom Stock vest equally over a three-year period. When vesting occurs, the Company pays the employee an amount equal to the then current share price times the number of Phantom Stock that have vested, plus the cumulative value of dividends applicable to the Company’s stock.

At the Company’s sole discretion, at the time the Phantom Stock vest, the Company has the ability to offer the employee to accept shares in lieu of cash. Upon a change in control of the Company, all outstanding Phantom Stock become immediately vested and payable.

As of March 31, 2007, the Company had issued 1,391,200 shares of Phantom Shares and in addition the Company has outstanding 117,500 Restricted Shares and for the quarter and nine months ended March 31, 2007, recognized general and administrative expense of $581,000 and $1,316,000, respectively. A liability has been recognized as of March 31, 2007 in the amount of $1.5 million in Other liabilities in the accompanying consolidated balance sheet. The amount of the liability will be remeasured at fair value as of each reporting date. No Phantom Stock has vested or has been paid as of March 31, 2007.

Defined Contribution Plans. The Company’s employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions based upon 10% of annual salaries. The Company also sponsors a qualified 401 (k) Plan which provides for matching. The cost to the Company under these plans for the quarter and nine months ended March 31, 2007 was $359,000 and $649,000, respectively.

NOTE 8—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 period. If warrants to issue common stock were exercised, the effect would be anti-dilutive and thus have been excluded for the computation of diluted earnings per share.

NOTE 9—HURRICANES KATRINA AND RITA

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

In January 2007, the Company reached a global settlement for $38.8 million with its insurance carrier. All but $0.1 million of the amount was received in the third fiscal quarter of 2007.

NOTE 10—COMMITMENTS AND CONTINGENCIES

Litigation. The Company is a party to litigation in the normal course of business. While the outcome of litigation against the Company cannot be predicted with certainty, management believes that the effect on its financial condition, results of operations and cash flows, if any, will not be material.

Lease Commitments. The Company has a non-cancelable operating lease for office space that expires on July 31, 2013. Future minimum lease commitments as of March 31, 2007 under the operating leases are as follows (in thousands):

12 Months Ending March 31,
2008	$	728
2009		728
2010		728
2011		728
2012		728
Thereafter		976
Total	$	4,616

F-33

Rent expense for the quarter and nine months ended March 31, 2007 was approximately $101,000 and $382,000, respectively.

Letters of Credit and Performance Bonds. The Company had $5.3 million in letters of credit and $42.2 million of performance bonds outstanding as of March 31, 2007.

Drilling Rig Commitments. The Company has entered into three drilling rig commitments ranging from 90 to 122 days, the latest commencing on March 31, 2007. Total commitments under these contracts to secure drilling rigs as of March 31, 2007 are approximately $17.5 million.

NOTE 11—SUBSEQUENT EVENT

On April 24, 2007, the Company conditionally agreed to purchase certain Gulf of Mexico shelf oil and natural gas properties form Pogo Producing Company for a cash consideration of $419.5 million. Based upon a third party reserve report, as of December 31, 2006, the properties included 20.2 million barrels of oil equivalent of proved reserves. The purchase is subject to customary closing conditions and adjustments, such as adjustments to the purchase price to reflect revenues, expenses and capital expenditures realized between the effective date of April 1, 2007 and the closing, which is expected in early June 2007.

The Company anticipates funding the acquisition by expanding its first lien revolver and doing a $700 million high yield private placement, a portion of which will be used to repay the second lien revolver facility.

F-34

ENERGY XXI (BERMUDA) LIMITED

CARVE-OUT FINANCIAL STATEMENTS FOR CASTEX

JUNE 30, 2006

F-35

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Energy XXI (Bermuda) Limited

We have audited the accompanying statements of revenues and direct operating expenses of certain oil and gas properties, as defined in the purchase and sale agreement (the “Carve-Out Financial Statement for Castex”) between Energy XXI Gulf Coast, Inc., a wholly owned subsidiary of Energy XXI (Bermuda) Limited (the “Company”) and 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. (collectively referred to as “Castex”) dated June 6, 2006 (the “Agreement”), for the twelve month periods ended June 30, 2006, 2005 and 2004. The Carve-Out Financial Statement for Castex is the responsibility of Castex’s management. Our responsibility is to express an opinion on the Carve-Out Financial Statement for Castex based on our audit.

We conducted our audit 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 Carve-Out Financial Statement for Castex is free from material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Carve-Out Financial Statement for Castex. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Carve-Out Financial Statement for Castex. We believe that our audit provides a reasonable basis for our opinion.

The accompanying Carve-Out Financial Statement for Castex was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 to the Carve-Out Financial Statement for Castex and is not intended to be a complete presentation of the revenues and expenses of the of certain oil and gas properties, as defined in the Agreement.

In our opinion, such Carve-Out Financial Statement for Castex presents fairly, in all material respects, the revenues and direct operating expenses as described in Note 1 to the Carve-Out Financial Statement for Castex for the twelve month periods ended June 30, 2006, 2005 and 2004 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2, the Carve-Out Financial Statements for Castex for the twelve month period ended June 30, 2006 have been restated.

/s/ UHY LLP

Houston, Texas

October 17, 2006

(March 12, 2007 as to the effects of the restatement discussed in Note 2)

F-36

ENERGY XXI (BERMUDA) LIMITED

CARVE-OUT FINANCIAL STATEMENTS FOR CASTEX

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

	Twelve Month Period Ended June 30, 2006		Twelve Month Period Ended June 30, 2005		Twelve Month Period Ended June 30, 2004
	(Restated)
Revenues:
Oil sales	$	7,865,454	$	1,307,290	$	152,971
Natural gas sales		53,021,396		3,683,819		66,487
Natural gas liquids		338,370		526,175		—
Total revenues		61,225,220		5,517,284		219,458
Direct Operating Expenses:
Lease operating expenses		11,060,400		709,775		60,381
Production and severance taxes		1,794,083		286,289		21,892
Ad valorem taxes		485,689		12,259		4,146
Total direct operating expenses		13,340,172		1,008,323		86,419
Excess of Revenues Over Direct Operating Expenses	$	47,885,048	$	4,508,961	$	133,039

See notes to the Carve-Out Financial Statements.

F-37

ENERGY XXI (BERMUDA) LIMITED

CARVE-OUT FINANCIAL STATEMENTS FOR CASTEX

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

JUNE 30, 2006

1. Basis of Preparation

On June 6, 2006 Energy XXI Gulf Coast, Inc. (the “Company”), a wholly owned subsidiary of Energy XXI (Bermuda) Limited, signed an agreement to acquire from 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. (collectively “Castex”) certain oil and gas properties as defined in the Purchase and Sale Agreement between the Company and Castex for approximately $308 million. The transaction closed on July 28, 2006. The accompanying statements of revenues and direct operating expenses relate to the operations of the oil and gas properties acquired by the Company. The acquisition was funded through the early exercise of warrants, cash on hand and debt.

The Statements of Revenues and Direct Operating Expenses associated with the assets were derived from the Castex accounting records. Direct operating expenses include lease operating expenses, ad valorem taxes and production taxes. General and administrative expenses, depreciation, depletion and amortization (DD&A) of oil and gas properties and federal and state income taxes have been excluded from operating expenses in the accompanying historical statements because the allocation of certain expenses would be arbitrary and would not be indicative of what such costs would have been had the purchased properties been operated as a stand alone entity.

Included in lease operating expenses for the twelve months ended June 30, 2006, 2005 and 2004 were workover expenses of $8,758,579, $284,144 and $—, respectively.

2. Restatement of Financial Statements

The Carve-Out Financial Statements for Castex for the twelve month period ended June 30, 2006 have been restated due to the improper inclusion of certain oil and natural gas royalties in revenue and production and severance taxes. This adjustment had no impact on the prior period financial statements. Follows is a summary of the impact of the restatement:

	As Previously Reported Twelve Month Period Ended June 30, 2006		Adjustments			Restated Twelve Month Period Ended June 30, 2006
Oil sales		8,807,883	$	(942,429	)	$	7,865,454
Natural gas sales		60,123,345		(7,101,949	)		53,021,396
Natural gas liquids		338,370		—			338,370
Total revenues		69,269,598		(8,044,378	)		61,225,220
Lease operating expenses		11,060,400		—			11,060,400
Production and severance taxes		9,838,461		(8,044,378	)		1,794,083
Ad valorem taxes		485,689		—			485,689
Total direct operating expenses		21,384,550		(8,044,378	)		13,340,172
Excess of Revenues Over Direct Operating Expenses	$	47,885,048	$	—		$	47,885,048

3. Summary of Significant Accounting Policies

Use of Estimates: The preparation of the Carve-Out 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 revenues and direct expenses during the reporting periods. The most significant financial estimates are based on remaining proved natural gas and oil reserves. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

Revenue Recognition: Revenues are recognized for oil and natural gas revenue under the entitlement method of accounting. Under the entitlement method, revenue is recognized, based on the owner’s net interest in the well, when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline or a purchaser of crude oil has occurred.

F-38

4. Supplemental Information On Oil and Gas Reserves (Unaudited)

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of the Castex oil 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)
Reserves at June 30, 2003		23			129
Production		(4	)		(11	)
Extensions and discoveries		63			2,502
Revisions of previous estimates		4			57
Reserves at June 30, 2004		86			2,677
Production		(46	)		(550	)
Extensions and discoveries		40			2,412
Revisions of previous estimates		48			589
Reserves at June 30, 2005		128			5,128
Production		(150	)		(6,290	)
Extensions and discoveries		22			1,162
Revisions of previous estimates		—			—
Purchases of minerals in place		1,176			70,319
Reserves at June 30, 2006		1,176			70,319

	Oil (MBbls)		Natural Gas (MMcf)
Proved developed oil and gas reserves as of:
June 30, 2006		855		39,354
June 30, 2005		128		5,128
June 30, 2004		86		2,677

Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the computation of the standardized measure of discounted future net cash flows relating to proved reserves and the changes in such cash flows in accordance with SFAS No. 69. The standardized measure is the estimated excess future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs and a discount factor. Income taxes are excluded the calculation as Castex’s tax basis in the properties is not indicative of the Company’s tax basis in the properties. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on period-end prices and any fixed and determinable future price changes provided by contractual arrangements in existence at year end. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. A discount rate of 10% is applied to the annual future net cash flows.

The methodology and assumptions used in calculating the standardized measure are those required by SFAS No. 69. The standardized measure is not intended to be representative of the fair market value of the proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended.

F-39

The standardized measure of discounted future net cash flows related to proved oil and gas reserves as of June 30, 2006, 2005 and 2004 are as follows (in millions):

	June 30,
	2006		2005		2004
Future cash inflows	$	522	$	46	$	21
Future production costs		94		5		3
Future development costs		62		—		—
10% annual discount per estimated timing of cash flow		89		11		6
Standardized measure of discounted future net cash flows at the end of the period	$	277	$	30	$	12

The primary changes in the standardized measure of discounted estimated future net cash flows for the twelve-month periods ended June 30, 2006, 2005 and 2004 were as follows (in millions):

	Twelve Month Period Ended June 30,
	2006			2005			2004
Standard measure beginning of period	$	30		$	12		$	—
Sales of oil and gas produced, net of production costs		(48	)		(5	)		(1	)
Extensions, discoveries and other additions					14			11
Net changes in price and production costs		(41	)		5			2
Purchases of minerals in place		323			—			—
Accretion of discount		3			1			—
Revision of previous quantity estimates		72			3			—
Changes in estimated future development costs		(62	)		—			—
Standardized Measure End of Period	$	277		$	30		$	12

F-40

MARLIN ENERGY OFFSHORE L.L.C.,

MARLIN TEXAS GP, L.L.C. AND MARLIN TEXAS, L.P.

COMBINED FINANCIAL STATEMENTS

F-41

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

of Energy XXI (Bermuda) Limited

We have audited the accompanying combined balance sheets of Marlin Energy Offshore L.L.C., Marlin Texas GP, L.L.C. and Marlin Texas, L.P. as of March 31, 2006, December 31, 2005, 2004 and 2003 and the related combined statements of operations, changes in member’s equity and cash flows for the three month period ended March 31, 2006 and each of the years ended December 31, 2005, 2004 and 2003. These financial statements are the responsibility of Energy XXI (Bermuda) Limited’s management. Our responsibility is to express an opinion on these 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of Marlin Energy Offshore L.L.C., Marlin Texas GP, L.L.C. and Marlin Texas, L.P. as of March 31, 2006, December 31, 2005, 2004 and 2003, and the combined results of operations and cash flows for the three month period ended March 31, 2006 and each of the years ended December 31, 2005, 2004 and 2003 in conformity with accounting principles generally accepted in the United States of America.

/s/ Grant Thornton LLP

Houston, Texas

November 13, 2006

F-42

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C. AND MARLIN TEXAS, L.P.

COMBINED BALANCE SHEETS

	March 31,		December 31,
	2006		2005		2004		2003
			(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	—	$	1,892	$	2,666	$	571
Receivables:
Oil and natural gas sales		20,237		21,352		12,508		8,141
Joint interest		6,354		12,180		3,297		198
Insurance		38,708		30,738		—		—
Prepaid expenses and other current assets		4,025		5,144		1,394		583
Total current assets		69,324		71,306		19,865		9,493
Property and equipment, net of depreciation, depletion, and amortization
Net oil and natural gas properties (using the full cost method of accounting)		314,495		303,293		270,872		86,373
Net other property and equipment		361		429		450		247
Net property and equipment		314,856		303,722		271,322		86,620
Total assets	$	384,180	$	375,028	$	291,187	$	96,113
Liabilities and Member’s Equity
Current liabilities:
Accounts payable	$	48,417	$	36,972	$	31,761	$	6,427
Joint owner advances		5,429		2,776		—		—
Undistributed oil and natural gas proceeds		2,490		10,997		3,871		2,447
Asset retirement obligations		292		286		—		—
Accrued liabilities		545		1,091		616		141
Total current liabilities		57,173		52,122		36,248		9,015
Asset retirement obligations, less current portion		36,781		36,035		33,448		3,833
Commitments and contingencies
Member’s equity		290,226		286,871		221,491		83,265
Total liabilities and member’s equity	$	384,180	$	375,028	$	291,187	$	96,113

The accompanying notes are an integral part of the combined financial statements.

F-43

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C. AND MARLIN TEXAS, L.P.

COMBINED STATEMENTS OF OPERATIONS

	For the Three Months
	Ended		For the Year Ended
	March 31,		December 31,
	2006		2005		2004		2003
			(In thousands)
Revenues
Oil sales	$	26,543	$	74,101	$	65,133	$	21,332
Natural gas sales		19,898		90,021		36,849		4,406
Total revenues		46,441		164,122		101,982		25,738
Operating cost and expenses:
Lease operating		10,907		36,920		16,658		5,722
Production taxes		199		615		558		99
Gathering and transportation		91		696		787		203
Depreciation, depletion and amortization		12,718		38,997		26,568		9,219
Accretion of asset retirement obligations		752		2,873		1,526		164
General and administrative		1,470		6,065		4,608		1,705
Total costs and expenses		26,137		86,166		50,705		17,112
Net income	$	20,304	$	77,956	$	51,277	$	8,626

The accompanying notes are an integral part of the combined financial statements.

F-44

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C. AND MARLIN TEXAS, L.P.

COMBINED STATEMENT OF CHANGES IN MEMBER’S EQUITY

	(In thousands)
Member’s equity at January 1, 2003	$	—
Member contribution		83,683
Increase in Due from Member		(9,044	)
Net income		8,626
Member’s equity at December 31, 2003		83,265
Member contribution		106,607
Increase in Due from Member		(19,658	)
Net income		51,277
Member’s equity at December 31, 2004		221,491
Increase in Due from Member		(12,576	)
Net income		77,956
Member’s equity at December 31, 2005		286,871
Increase in Due from Member		(16,949	)
Net income		20,304
Member’s equity at March 31, 2006	$	290,226

The accompanying notes are an integral part of the combined financial statements.

F-45

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C. AND MARLIN TEXAS, L.P.

COMBINED STATEMENTS OF CASH FLOWS  

	For the Three Months
	Ended			For the Year Ended
	March 31,			December 31,
	2006			2005			2004			2003
				(In thousands)
Cash flows from operating activities:
Net income	$	20,304		$	77,956		$	51,277		$	8,626
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		12,718			38,997			26,568			9,219
Accretion of asset retirement obligations		752			2,873			1,526			164
Changes in operating assets and liabilities—
(Increases) decreases in receivables		6,941			(17,727	)		(7,466	)		(8,339	)
(Increases) decreases prepaid expenses		1,119			(3,750	)		(811	)		(583	)
Increases (decreases) in accounts payable		4,029			18,373			10,123			4,814
Net cash provided by operating activities		45,863			116,722			81,217			13,901
Cash flows from investing activities:
Cash paid for acquisitions		—			—			(106,607	)		(83,683	)
Capital expenditures		(47,879	)		(104,920	)		(59,464	)		(4,286	)
Insurance payments received		17,073			—			—			—
Net cash used for investing activities		(30,806	)		(104,920	)		(166,071	)		(87,969	)
Cash flows from financing activities:
Contribution from member		—			—			106,607			83,683
Increase in amount due from member		(16,949	)		(12,576	)		(19,658	)		(9,044	)
Net cash provided by financing activities		(16,949	)		(12,576	)		86,949			74,639
Increase (decrease) in cash and cash equivalents		(1,892	)		(774	)		2,095			571
Cash and cash equivalents, beginning of period		1,892			2,666			571			—
Cash and cash equivalents, end of period	$	—		$	1,892		$	2,666		$	571

The accompanying notes are an integral part of the combined financial statements.

F-46

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C. AND MARLIN TEXAS, L.P.

NOTES TO COMBINED FINANCIAL STATEMENTS

1. Nature of Operations and Summary of Significant Accounting Policies

Nature of Business

On April 4, 2006, Energy XXI Gulf Coast, Inc. (“Energy XXI”), acquired from Marlin Energy, L.L.C. (the “Member”) all of its membership interest in Marlin Energy Offshore, L.L.C. and Marlin Texas GP, L.L.C. and its limited partner interests in Marlin Texas, L.P. (collectively the “Company”) for an aggregate consideration of approximately $448 million (the “Acquisition”).

The Member, headquartered in Lafayette, Louisiana, was formed on May 28, 2003 for the purpose of acquiring oil and natural gas leases and other oil and natural gas interests in the Gulf of Mexico and onshore in Texas and Louisiana.

In preparation of the Acquisition, the Member distributed certain assets of the Company that it chose to retain. Furthermore, in connection with the Acquisition, certain employees of the Company also sold interests they held in properties owned by the Company. These ownership interests arose as the Company permitted its employees to participate as equity owners in certain properties developed by the Company.

In addition, Energy XXI did not employ or offer any permanent employment to management of the Company, and did not assume any liabilities of the Member or the Company other than those directly related to the properties transferred with the Company as part of the Acquisition. Following the Acquisition, the Member continued to own and operate oil and natural gas interests and related properties.

The Company was headquartered in Lafayette, Louisiana, and was engaged in the exploration, development, and operation of oil and natural gas properties located in the U.S. Gulf Coast and Gulf of Mexico.

Principles of Combination and Reporting

The combined financial statements of the Company include the accounts of Marlin Energy Offshore, LLC, Marlin Texas GP, L.L.C. and the limited partnership interest in Marlin Texas, L.P. The oil and natural gas properties included in the combined financial statements of the Company include only those that were acquired as part of the Acquisition. Oil and natural gas receivables, joint interest billing, joint owner advances, and certain prepaid expenses that are directly associated with the oil and natural gas properties acquired were also included in the combined financial statements of the Company. All other significant working capital accounts, not necessarily associated specifically with the oil and natural gas properties acquired have been included in the combined financial statements of the Company. Derivative instruments entered into by the Member related to the interest acquired were retained by the Member and therefore have not been included in the accompanying combined financial statements. All significant intercompany transactions have been eliminated in the combined financial statements.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles 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 date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, as well as estimates of expenses related to legal, environmental and other contingencies. Actual results could differ from those estimates.

Furthermore, as part of the preparation and presentation of the combined financial statements of the Company, certain assumptions and estimates were used, including the amount and timing of capital contributions from the Member, amounts due from the Member and the historical depletion of oil and natural gas properties acquired from the Member as part of the Acquisition.

Cash and Cash Equivalents

The Company considers all highly liquid instruments purchased with a maturity of three months or less to be cash equivalents.

F-47

Allowance for Doubtful Accounts

The Company establishes 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 March 31, 2006, December 31, 2005 and 2004, no allowance for doubtful accounts was necessary.

Oil and Natural Gas Properties

The Company uses 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 oil and natural gas properties. This includes any internal costs that are directly related to 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 natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unproved properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. The Company excludes these costs until the project is evaluated and proved reserves are established or impairment is determined. 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 and equipment, including office and computer equipment, 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.

General and Administrative Costs

Under the full cost method of accounting, a portion or the Company’s general and administrative expenses that are directly identified with the Company’s acquisition, exploration and development activities are 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 of the Company 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. General and administrative expenses are shown net of capitalized general and administrative cost of $281,000, $1,103,000, $830,000 and $319,000 for the three months ending March 31, 2006, the years ending December 31, 2005 and 2004, and for the period from inception (June 17, 2003) through December 31, 2003, respectively.

Asset Retirement Obligations

The Company accounts for costs associated with abandoning platforms, wells and other facilities, in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143 Accounting for Asset Retirement Obligations (“SFAS No. 143”). Obligations associated with abandoning long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has acquired and constructed. The asset retirement obligations are recorded at fair value and accretion expense increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost included in the depreciable base of oil and natural gas properties.

Revenue Recognition

The Company recognizes oil and natural gas revenue under the entitlement method of accounting. Under the entitlement method, revenue is recognized, based on the Company’s net interest in the well, when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline or a tanker lifting has occurred.

F-48

Income Taxes

The Company has elected to be treated as a partnership for federal and state income tax purposes. Accordingly, all tax obligations are borne solely by the member of the Company.

New Accounting Standards

The Company discloses the existence and effect of accounting standards issued but not yet adopted by the Company with respect to accounting standards that may have an impact on the Company when adopted in the future.

Accounting Changes and Error Corrections—In May 2005, the FASB issued SFAS No. 154 Accounting Changes and Error Corrections (“SFAS No. 154”), which is a replacement of APB Opinion No. 20 Accounting Changes (“APB 20”), and SFAS No. 3 Reporting Accounting Changes in Interim Financial Statements (“SFAS No. 3”). SFAS No. 154 applies to all voluntary changes in accounting principle, and changes the requirements for accounting for and reporting of a change in accounting principle. The provisions of SFAS 154 will have an impact on the Company’s financial statements in the future should there be voluntary changes in accounting principles. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company adopted SFAS No. 154 on January 1, 2006.

2. Hurricanes Katrina and Rita

As a result of Hurricanes Katrina and Rita in August and September of 2005, respectively, the Company sustained damage to their oil and natural gas properties. The Company incurred costs to restore production at the damaged facilities and has filed claims with its insurance company for reimbursement of these costs. The insurance coverage is an indemnity program that provides for reimbursement after funds are expended. The Company has recorded the expected reimbursable costs in excess of the insurance deductible as a receivable in the combined balance sheets. As of March 31, 2006 and December 31, 2005, the reimbursable amount was $38.7 million and $30.7 million, respectively.

On June 30, 2004, the Company acquired oil and natural gas properties in the U.S. Gulf Coast and the Gulf of Mexico from the J.M Huber Corporation, for approximately $83.9 million in cash and the potential for participation by the seller in certain future revenues based upon specified sales prices. The acquisition cost was allocated to oil and natural gas properties ($111.8 million) and asset retirement obligations ($27.9 million).

On February 1, 2004, the Company acquired oil and natural gas properties in the state of Texas from Daimon Partners I, Ltd. for approximately $22.7 million in cash. The acquisition cost was allocated to oil and natural gas properties ($22.9 million) and asset retirement obligations ($.2 million).

On June 17, 2003, the Company acquired oil and natural gas properties in the U.S. Gulf Coast and the Gulf of Mexico from Duke Energy Hydrocarbons, for approximately $83.7 million in cash. The acquisition cost was allocated to oil and natural gas properties ($87.4 million) and asset retirement obligations ($3.7 million).

4. Oil and Natural Gas Properties and Other Property and Equipment

Net capitalized costs related to our oil and natural gas producing activities and other property are as follows (in thousands):

		March 31,			December 31,
		2006			2005			2004			2003
Proved oil and natural gas properties	$	401,484		$	377,637		$	306,470		$	95,556
Accumulated depreciation, depletion and amortization		(86,989	)		(74,344	)		(35,598	)		(9,183	)
Net oil and natural gas properties	$	314,495		$	303,293		$	270,872		$	86,373
Other property and equipment	$	874		$	869		$	639		$	283
Accumulated depreciation		(513	)		(440	)		(189	)		(36	)
Net other property and equipment	$	361		$	429		$	450		$	247
Net other property and equipment	$	314,856		$	303,722		$	271,322		$	86,620

F-49

5. Asset Retirement Obligations

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

		Three Months Ending March 31,			Year Ending December 31,
		2006			2005			2004		2003
ARO at beginning of year	$	36,321		$	33,448		$	3,833	$	—
Liabilities acquired from acquisitions of oil an natural gas properties		—			—			28,089		3,669
Accretion expense		752			2,873			1,526		164
ARO at end of year		37,073			36,321			33,448		3,833
Less: Current portion of asset retirement obligation		(292	)		(286	)		—		—
Long-term asset retirement obligation	$	36,781		$	36,035		$	33,448	$	3,833

There was no cash paid for interest or income taxes during the periods presented in the combined statements of cash flows.

7. Commitments and Contingencies

The Company is subject to claims in the normal course of business. While the outcome of asserted and unasserted claims or other potential proceedings against the entities cannot be predicted with certainty, management believes that the effect on its financials condition, results of operations and cash flows, if any, will not be material.

8. Concentrations of Credit Risk

Major Customers

The Company’s production is sold on month-to-month contracts at prevailing prices. The following table identifies customers it derived 10% or more of the Company’s net oil and natural gas revenues during the period. Based on the availability of other customers, the Company does not believe the loss of any of these customers would have a significant effect on its results of operations or financial condition.

	Three Months Ending March 31,		Year Ending December 31,
Customer	2006		2005		2004		2003
Cinergy Marketing & Trading	(a	)	(a	)	(a	)	11	%
Chevron Texaco Products Company	54	%	43	%	12	%	(a	)
Cokinos Natural Gas Co.	(a	)	(a	)	12	%	(a	)
Dominion Field Services, Inc.	(a	)	(a	)	12	%	(a	)
William G. Helis Company	(a	)	(a	)	10	%	(a	)
Louis Dreyfus Energy Services	15	%	20	%	(a	)	(a	)

(a)Less than 10%

Accounts Receivable

Substantially all of the Company’s 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 the Company’s 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, the Company does not expect that termination of sales to any of its current purchasers would have a material adverse effect on its ability to find replacement purchasers and to sell its production at favorable market prices.

Cash and Cash Equivalents

The Company is subject to concentrations of credit risk with respect to its cash and cash equivalents, which the Company attempts to minimize by maintaining its 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.

The Company includes fair value information in the notes to combined financial statements when the fair value of its financial instruments is different from the book value. The Company believes that the carrying value of its cash and cash equivalents, receivables, accounts payable, and accrued liabilities, materially approximates fair value due to the short-term nature and the terms of these instruments.

F-50

10. Supplementary Oil and Gas Information (Unaudited)

Proved Reserve Estimates

The following estimates of the net proved oil and natural gas reserves of the Company are based on evaluations prepared by our engineers and third-party reservoir engineers. Reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission 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 escalations except by contractual arrangements. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise that those of producing oil and natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

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

	Oil (MBbls)			Natural Gas (MMcf)
Proved reserves at January 1, 2003		—			—
Purchases of minerals in place		1,864			34,421
Extensions, discoveries, improved recovery and other additions		583			7,251
Revisions to previous estimates		(439	)		(2,991	)
Production, January 1, 2003 to December 31, 2003		(135	)		(4,260	)
Proved reserves at January 1, 2004		1,873			34,421
Purchases of minerals in place		11,788			45,174
Extensions, discoveries, improved recovery and other Additions		393			5,597
Revisions to previous estimates		410			(7,973	)
Production, January 1, 2004 to December 31, 2004		(840	)		(10,730	)
Proved reserves at January 1, 2005		13,624			66,489
Extensions, discoveries, improved recovery and other Additions		1,387			6,294
Revisions to previous estimates		1,539			5,723
Production, January 1, 2005 to December 31, 2005		(1,740	)		(9,478	)
Proved reserves at January 1, 2006		14,810			69,028
Revisions to previous estimates		(683	)		384
Production, January 1, 2006 to March 31, 2006		(469	)		(2,448	)
Proved reserves at March 31, 2006		13,658			66,964
Proved Developed Reserves
March 31, 2006		8,970			44,549
December 31, 2005		9,255			45,020
December 31, 2004		10,218			50,017
December 31, 2003		1,405			25,816

Standardized Measure of Discounted Future Net Cash Flows

The following tables set forth the computation of the standardized measure of discounted future net cash flows and changes in standardized measures of future cash flows relating to proved reserves and the changes in such cash flows in accordance with SFAS No. 69, Disclosure about Oil and Gas Producing Activities (“SFAS 69”). The standardized measure is the estimated future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs, discounted at 10%. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on period-end prices and any fixed and determinable future escalation provided by contractual arrangements in existence at year end. Escalation based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. Estimated future income tax expenses are not considered as the Company is not a tax paying entity.

F-51

The methodology and assumptions used in calculating the standardized measure are those required by SFAS 69. The standardized measure is not intended to be representative of the fair market value of the proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended.

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves follows (in millions):

		March 31,			December 31,
		2006			2005			2004			2003
Future cash inflows	$	1,413		$	1,570		$	1,014		$	275
Future costs:
Production costs		(313	)		(329	)		(307	)		(71	)
Development costs		(182	)		(198	)		(186	)		(37	)
Dismantlement and abandonment costs		(51	)		(54	)		(46	)		(9	)
Future net cash flows before 10% discount factor		867			989			475			158
10% annual discount factor		(252	)		(250	)		(162	)		(58	)
	$	615		$	739		$	313		$	100

Changes in standardized measure from January 1, 2002 through March 31, 2006 (in millions):

		Three Months Ending March 31,			Year Ending December 31,
		2006			2005			2004			2003
Standardized Measure, beginning of period	$	739		$	313		$	100		$	—
Sales and transfers net of production costs		(73	)		(194	)		(111	)		(32	)
Net changes in price, net of production costs		(81	)		389			87			29
Extensions, discoveries and improved recovery, net of future production and development costs		—			100			28			31
Revisions of quantity estimates		(21	)		30			(100	)		(30	)
Accretion of discount		18			31			10			—
Purchases of minerals in place		—			—			224			94
Development costs incurred for the period		33			70			75			8
Net change in standardize measure		(124	)		426			213			100
Standardized measure, end of period	$	615		$	739		$	313		$	100

F-52

ENERGY XXI (BERMUDA) LIMITED

CARVE-OUT FINANCIAL STATEMENTS FOR POGO

NINE MONTH PERIODS ENDED

MARCH 31, 2007 AND 2006 (UNAUDITED)

AND YEARS ENDED

DECEMBER 31, 2006, 2005 AND 2004 (AUDITED)

F-53

ENERGY XXI (BERMUDA) LIMITED

CARVE-OUT FINANCIAL STATEMENTS FOR POGO

DECEMBER 31, 2006, 2005 AND 2004

CONTENTS

	Page
Report of Independent Registered Public Accounting Firm	F-55
Statement of Revenues and Direct Operating Expense	F-56
Notes to Statements of Revenues and Direct Operating Expenses	F-57

F-54

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders

Energy XXI (Bermuda) Limited

We have audited the accompanying statements of revenues and direct operating expenses of certain oil and gas properties, as defined in the purchase and sale agreement (the “Carve-Out Financial Statements for Pogo”) between Energy XXI GOM, LLC, a wholly owned subsidiary of Energy XXI (Bermuda) Limited (the “Company”) and Pogo Producing Company (“Pogo”), dated April 24, 2007 (the “Agreement”), for each of the years in the three-year period ended December 31, 2006. The Carve-Out Financial Statements for Pogo are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Carve-Out Financial Statements for Pogo 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 audits to obtain reasonable assurance about whether the Carve-Out Financial Statements for Pogo is free from material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Carve-Out Financial Statements for Pogo. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Carve-Out Financial Statements for Pogo. We believe that our audits provide a reasonable basis for our opinion.

The accompanying Carve-Out Financial Statements for Pogo were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 to the Carve-Out Financial Statements for Pogo and are not intended to be a complete presentation of the revenues and expenses of the certain oil and gas properties, as defined in the Agreement.

In our opinion, the Carve-Out Financial Statements for Pogo referred to above present fairly, in all material respects, the revenues and direct operating expenses as described in Note 1 to the Carve-Out Financial Statements for Pogo for each of the years in the three-year period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

May 24, 2007

F-55

ENERGY XXI (BERMUDA) LIMITED

CARVE-OUT FINANCIAL STATEMENTS FOR POGO

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

	Nine Months Ended March 31,				Year Ended December 31,
	2007		2006		2006		2005		2004
	(Unaudited)
REVENUES
Oil sales	$	72,491,052	$	80,621,741	$	110,992,467	$	127,348,546	$	134,755,037
Natural gas sales		26,644,357		29,811,314		34,318,535		48,158,216		52,376,704
Natural gas liquids		2,550,388		2,336,812		3,407,376		3,969,524		5,806,160
TOTAL REVENUES		101,685,797		112,769,867		148,718,378		179,476,286		192,937,901
DIRECT OPERATING EXPENSES
Lease operating expenses		35,381,420		31,689,097		30,665,711		35,337,059		23,091,439
Pipeline operating expenses		146,997		297,052		146,602		1,605,081		10,945
Production and other taxes		402,863		263,643		491,210		646,829		602,279
TOTAL DIRECT OPERATING EXPENSES		35,931,280		32,249,792		31,303,523		37,588,969		23,704,663
EXCESS OF REVENUES OVER DIRECT OPERATING EXPENSES	$	65,754,517	$	80,520,075	$	117,414,855	$	141,887,317	$	169,233,238

See notes to Statements of Revenues and Direct Operating Expenses.

F-56

NOTE 1 - BASIS OF PREPARATION

On April 24, 2007 Energy XXI GOM, LLC (the “Company”), a wholly owned subsidiary of Energy XXI (Bermuda) Limited, signed an agreement to acquire from Pogo Producing Company (“Pogo”) certain offshore oil and gas properties located in the Gulf of Mexico near Louisiana and Texas (the “Properties”) as defined in the Purchase and Sale Agreement between the Company and Pogo for approximately $419.5 million before accounting for the results of operations between the April 1, 2007 effective date and the closing date and other purchase price adjustments. The obligations of the parties under the agreement are subject to certain closing conditions including, among other things, accuracy of representations and warranties and other specified closing conditions. Under the agreement, the Company will assume certain liabilities related to the Properties, including asset retirement obligations and gas imbalances. The transaction is expected to close in early June 2007. The accompanying statements of revenues and direct operating expenses relate to the operations of the oil and gas properties to be acquired by the Company. The acquisition will be funded with the proceeds from the issuance of additional debt. Some of the Properties included in the Purchase and Sale Agreement are subject to certain preferential purchase rights by the existing property owners. The Company does not expect the exercise of these preferential rights to have a material effect on the accompanying statements of revenues and direct operating expenses.

The statements of revenues and direct operating expenses associated with the Properties were derived from the Pogo accounting records. During the years presented, the Properties were not accounted for or operated as a consolidated entity or as a separate division by Pogo. Revenues and direct operating expenses for the Properties included in the accompanying statements represent the net collective working and revenue interests to be acquired by the Company. The revenues and direct operating expenses presented herein relate only to the interests in the producing oil and natural gas properties and pipeline assets which will be acquired and do not represent all of the oil and natural gas operations of Pogo, other owners, or other third party working interest owners. Direct operating expenses include lease operating expenses, pipeline operating expenses and production and other taxes. General and administrative expenses, depreciation, depletion and amortization (DD&A) of oil and gas properties and federal and state taxes have been excluded from direct operating expenses in the accompanying statements of revenues and direct operating expenses because the allocation of certain expenses would be arbitrary and would not be indicative of what such costs would have been had the Properties been operated as a stand alone entity. Pogo accounted for the Properties under the successful efforts method of accounting for oil and gas activities, while the Company uses the full cost method. Accordingly, exploration expenses and dry hole costs are not applicable to this presentation. Full separate financial statements prepared in accordance with accounting principles generally accepted in the United States of America do not exist for the Properties and are not practicable to prepare in these circumstances. The statements of revenues and direct operating expenses presented are not indicative of the results of operations of the Properties on a go forward basis due to changes in the business and the omission of various operating expenses.

Included in lease operating expenses for the nine months ended March 31, 2007 and 2006 and the years ended December 31, 2006, 2005 and 2004 were workover expenses and repairs of $29,157,000, $18,297,396, $8,384,000, $18,342,000 and $6,530,000, respectively, of which hurricane related workover expenses and repairs were $12,750,000, $8,566,000, $7,942,000, $17,661,000 and $5,878,000, respectively.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates: The preparation of the Carve-Out Financial Statements for Pogo 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 revenues and expenses during the reporting periods. Although these estimates are based on management’s best available knowledge of current and future events, actual results could be different from those estimates.

Revenue Recognition: Revenues are recognized for oil and natural gas sales under the sales method of accounting. Under this method, revenues are recognized on production as it is taken and delivered to its purchasers. The volumes sold may be more or less than the volumes entitled to, based on the owner’s net interest in the Properties. These differences result from production imbalances, which are not significant and reflected as adjustments to proved reserves and future cash flows in the unaudited supplementary oil and gas data included herein.

F-57

NOTE 3 - SUPPLEMENTAL INFORMATION ON OIL AND GAS RESERVES (UNAUDITED)

Estimated Quantities of Oil and Natural Gas Reserves

The following estimates of net proved oil and natural gas reserves of the Properties located entirely within the United States of America, are based on evaluations prepared by Pogo 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 than 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 million cubic feet (“MMcf”) for each of the years were as follows:

	Oil (MBbls)			Natural Gas (MMcf)
Proved reserves:
January 1, 2004		19,160			59,865
Production		(4,177	)		(10,583	)
Extensions and discoveries		134			609
Revisions of previous estimates		1,022			(638	)
Purchases of minerals in place		2,508			5,718
Sales of minerals in place		(916	)		(1,444	)
December 31, 2004		17,731			53,527
Production		(2,711	)		(6,328	)
Extensions and discoveries		320			3,470
Revisions of previous estimates		507			(2,381	)
December 31, 2005		15,847			48,288
Production		(2,811	)		(8,022	)
Extensions and discoveries		96			525
Revisions of previous estimates		1,662			(3,321	)
December 31, 2006		14,794			37,470

	Oil (MBbls)		Natural Gas (MMcf)
Proved developed reserves:
December 31, 2004		12,813		34,398
December 31, 2005		13,309		29,114
December 31, 2006		11,539		24,267

Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the computation of the standardized measure of discounted future net cash flows relating to proved reserves and the changes in such cash flows in accordance with Statement of Financial Accounting Standard No. 69. The standardized measure is the estimated excess future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs and a discount factor. Income taxes are excluded from the calculation as Pogo’s tax basis in the properties is not indicative of the Company’s tax basis in the properties. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on December 31, or year-end prices and any fixed and

F-58

determinable future price changes provided by contractual arrangements in existence at year-end. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end reserves are based on December 31, or year-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. A discount rate of 10% is applied to the annual future net cash flows.

	December 31,
	2006			2005			2004
	(In Millions)
Future cash inflows	$	1,077		$	1,408		$	1,106
Future production and development costs		(353	)		(297	)		(231	)
Future net cash flows - 10% annual discount for estimated timing of cash flows		(180	)		(271	)		(192	)
Standardized measure of discounted future net cash flows	$	544		$	840		$	683

The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2006, 2005 and 2004:

	2006			2005			2004
				(In Millions)
Beginning of year	$	840		$	683		$	561
Net change in sales and transfer prices and in production (lifting) costs related to future production		(164	)		308			154
Net change due to revisions in quantity estimates		36			5			25
Changes in estimated future development costs		(82	)		(62	)		(5	)
Accretion of discount		84			68			56
Changes in production rate and other		(124	)		(46	)		(42	)
Net change due to extensions, discoveries and improved recovery		5			18			6
Net change due to purchases and sales of minerals in place		—			—			78
Sales and transfers of oil and gas produced during the period, net of production costs		(117	)		(142	)		(169	)
Previously estimated development costs incurred during the period		66			8			19
End of year	$	544		$	840		$	683

F-59

ENERGY XXI (BERMUDA) LIMITED

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

MARCH 31, 2007,

UNAUDITED PRO FORMA CONSOLIDATED INCOME STATEMENT

FOR THE NINE MONTHS ENDED MARCH 31, 2007

AND

FROM JULY 25, 2005 (INCEPTION) TO JUNE 30, 2006

F-60

ENERGY XXI (BERMUDA) LIMITED

PRO FORMA FINANCIAL STATEMENTS

(UNAUDITED)

The Company acquired certain oil and gas properties and related assets and liabilities from Marlin, Castex and Pogo on April 4, 2006, July 28, 2006 and June 8, 2007, respectively. The following summarized pro forma income statement for the nine month period ended March 31, 2007 has been prepared to reflect the acquisition of Castex and Pogo on July 1, 2006. The following summarized pro forma consolidated income statement for the period from July 25, 2005 (inception) to June 30, 2006 has been prepared to reflect the acquisition of Marlin, Castex and Pogo on July 1, 2005. Pro forma balance sheet information at March 31, 2007 has been prepared to reflect the acquisition certain assets from Pogo as if the transaction occurred on March 31, 2007. Pro forma consolidated balance sheet adjustments related to the acquisition of Marlin and Castex as of March 31, 2007 are not required as the Marlin and Castex acquisitions are reflected in the Company’s March 31, 2007 unaudited consolidated balance sheet. These unaudited pro forma consolidated financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if the Company had completed the acquisition at an earlier date or the results that will be attained in the future. These pro forma consolidated financial statements should be read in conjunction with the audited June 30, 2006 and unaudited March 31, 2007 consolidated financial statements of Energy XXI (in thousands except share and per share data).

F-61

ENERGY XXI (BERMUDA) LIMITED

PRO FORMA CONSOLIDATED BALANCE SHEET

MARCH 31, 2007

(Unaudited)

BASIS OF PRESENTATION

Pro forma balance sheet information at March 31, 2007 has been prepared to reflect the acquisition certain assets from Pogo as if the transaction occurred on March 31, 2007.

		Energy XXI Historical	Pro Forma Adjustments																Energy XXI Pro Forma
		March 31, 2007		Loan Proceeds					Pogo					Other Costs					March 31, 2007
				(in thousands except share data)
Current assets	$	132,484	$	409,832		(1	)	$	(409,832	)	(2	)	$	800		(3	)	$	133,284
Property, plant and equipment, net		928,942							411,674		(2	)		3,000		(3	)		1,367,916
									24,300		(2	)
														17,250		(3	)
Non current assets		6,942												(2,400	)	(3	)		21,792
Total assets	$	1,068,368	$	409,832				$	26,142				$	18,650				$	1,522,992
Current liabilities	$	79,247																$	79,247
Long-term debt - Revolver and other		207,712		(15,168	)	(1	)							26,750		(3	)		219,294
Long-term debt - Second Lien		325,000		(325,000	)	(1	)												—
Private placement debt		—		750,000		(1	)												750,000
Asset retirement obligation		45,981							24,300		(2	)							70,281
Other non current liabilities		14,158							1,842		(2	)		(2,800	)	(4	)		13,200
Equity		396,270												(5,300	)	(4	)		390,970
Total liabilities and equity	$	1,068,368	$	409,832				$	26,142				$	18,650				$	1,522,992
Common shares issued and outstanding		84,049,115																	84,049,115

(1)   To reflect proceeds from the private placement, repayment of Second Lien and repayment of a portion of the Revolver.

(2)   To record the acquisition of Pogo. Total cash purchase price of $409.8 million plus assumption of gas balancing and ad valorem tax liabilities ($1.8 million) and asset retirement obligation ($24.3 million).

(3)   To reflect costs and expenses associated with the Pogo acquisition and offering ($.8 million prepaid insurance, $3 million seismic, $17.25 million capitalized debt issue cost associated with the private placement, $5.7 million cash expense associated with the revolver refinance cost and of $2.4 million write -off of previously capitalized revolver debt issue cost).

(4)   To reflect the write-off of $8.1 million in debt issue cost expense ($5.7 million cash plus $2.4 million previously capitalized), net of tax (65%) and to reduce deferred tax expense (35%).

F-62

ENERGY XXI (BERMUDA) LIMITED

PRO FORMA CONSOLIDATED INCOME STATEMENT

NINE MONTH PERIOD ENDED MARCH 31, 2007

(Unaudited)

BASIS OF PRESENTATION

The summarized pro forma income statement for the nine month period ended March 31, 2007 has been prepared to reflect the acquisition of Castex and Pogo on July 1, 2006. Castex was acquired on July 28, 2006 and therefore, the pro forma adjustments include revenue and expenses related to the Castex acquisition for the period from July 1, 2006 to July 28, 2006. Pogo was acquired on June 8, 2007 and therefore, the pro forma adjustments include revenue and expenses related to the Pogo acquisition for the period from July 1, 2006 to March 31, 2007. 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 the Company had completed the acquisitions at an earlier date or the results that will be attained in the future. These pro forma financial statements should be read in conjunction with the unaudited March 31, 2007 and audited June 30, 2006 financial statements of the Company (in thousands except share and per share data).

	Energy XXI Historical Nine Months Ended			Pro Forma Adjustments						Energy XXI Pro Forma Nine Months Ended
	March 31, 2007			Castex			Pogo			March 31, 2007
	(in thousands, except share and per share data)
Revenue	$	222,568		$	5,698(1	)	$	101,686(5	)	$	329,952
Production costs		36,547			3,469(1	)		35,931(5	)		83,447
								7,500(6	)
Depreciation, depletion and amortization		88,055			3,496(2	)		55,723(7	)		147,274
General and administrative expenses		26,505			—			5,063(8	)		31,568
Derivative (gains) losses and accretion of
asset retirement obligation		(491	)		54(3	)		1,823(9	)		1,386
Interest and other income		(1,599	)		—			—			(1,599	)
Interest expense		39,653			1,823(4	)		29,124(10	)		70,600
Income before income taxes		33,898			(3,144	)		(33,478	)		(2,724	)
Income tax expense (benefit)		11,976			(1,111)(11	)		(11,828)(11	)		(963	)
Net income (loss)	$	21,922		$	(2,033	)	$	(21,650	)	$	(1,761	)
Earnings per share - Basic (12)	$	0.26								$	(0.02	)
Earnings per share - Diluted (12)	$	0.26								$	(0.02	)

Pro Forma Adjustments Related to the Acquisition

(1) To reflect the historical revenue and operating expenses of Castex for the period from July 1, 2006 to July 28, 2006.

(2) To reflect additional Castex depreciation, depletion and amortization for production from July 1, 2006 to July 28, 2006 based on Castex’s actual production volumes for the period July 1, 2006 to July 28, 2006 of 143,748 BOE at the estimated pro forma depreciation, depletion and amortization rate of $24.31 per BOE.

(3) To reflect additional asset retirement obligation accretion for Castex for the period July 1, 2006 to July 28, 2006.

(4) To reflect additional interest expense associated with the Castex acquisition for the period July 1, 2006 through July 28, 2006 based on incremental borrowings of $229,000 at an interest rate of 8.6% and $296 of amortization of incremental debt issue costs associated with the Castex acquisition.

(5) To reflect the historical revenue and operating expenses of Pogo for the period from July 1, 2006 to March 31, 2007.

(6) To reflect additional wind storm insurance premiums of $10 million annually pro-rated for the nine month period.

(7) To reflect additional Pogo depreciation, depletion and amortization for production from July 1, 2006 to March 31, 2007 based on Pogo’s actual production volumes for the period July 1, 2006 to March 31, 2007 of 1,870,942 BOE at the estimated pro forma depreciation, depletion and amortization rate of $24.31 per BOE and to adjust Energy XXI’s historical production of 4,015,276 BOE to the $24.31 per BOE rate.

F-63

ENERGY XXI (BERMUDA) LIMITED

PRO FORMA CONSOLIDATED INCOME STATEMENT

NINE MONTH PERIOD ENDED MARCH 31, 2007

(Unaudited)

(8) To reflect incremental general and administrative expenses expected to be incurred as a result of the Pogo acquisition of $9 million annually, less 25% which is expected to be capitalized related directly to property acquisition, exploration and development activities, pro-rated for the nine month period ended March 31, 2007.

(9) To reflect additional asset retirement obligation accretion for Pogo acquisition for the period July 1, 2006 to March 31, 2007 based on the present value of the incremental asset retirement obligation of $24.3 million using an accretion rate of 10%, pro-rated for the nine month period ended March 31, 2007.

(10) To reflect additional interest expense associated with the Pogo acquisition for the period July 1, 2006 through March 31, 2007 based on a 10% interest rate on $750 million of New Senior Notes, a 7% interest rate on the revolving credit facility, a 7.1% interest rate on all additional borrowings and $2.8 million of amortization of debt issue costs associated with the Pogo acquisition, pro-rated for the nine month period ended March 31, 2007.  Interest expense excludes non-recurring expenses of $8.1 million ($5.3 million net of tax) related to the refinancing of the Company’s revolving credit facility.

(11) To adjust the tax benefit at an effective rate of 35.33%.

(12) The basic and diluted weighted average shares of stock outstanding for the nine month period ended March 31, 2007 were 84,049,115.

F-64

ENERGY XXI (BERMUDA) LIMITED

PRO FORMA CONSOLIDATED INCOME STATEMENT

PERIOD FROM JULY 25, 2005 (INCEPTION) TO JUNE 30, 2006

(Unaudited)

BASIS OF PRESENTATION

The summarized pro forma consolidated income statement for the period from July 25, 2005 (inception) to June 30, 2006 has been prepared to reflect the acquisition of Marlin, Castex and Pogo on July 1, 2005. Marlin was acquired on April 4, 2006, therefore the pro forma adjustments include revenue and direct operating expenses for the period from July 1, 2005 to April 3, 2006. Castex and Pogo were acquired on July 28, 2006 and June 8, 2007, respectively, and therefore, the pro forma adjustments include revenue and expenses related to the Castex and Pogo acquisitions for the twelve months ended June 30, 2006. These unaudited pro forma consolidated financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if the Company had completed the acquisitions at an earlier date or the results that will be attained in the future. These pro forma consolidated financial statements should be read in conjunction with the June 30, 2006 audited consolidated financial statements of the Company (in thousands except share and per share data).

	Energy XXI Historical Period From July 25, 2005 (inception)			Pro Forma Adjustments									Energy XXI
	to June 30, 2006			Marlin			Castex			Pogo			Pro Forma
	(in thousands except share and per share data)
Revenue	$	47,112		$	109,998(1	)	$	61,225(7	)	$	154,655(10	)	$	372,990
Production costs		9,986			34,165(1	)		13,340(7	)		33,775(10	)		101,266
											10,000(11	)
Depreciation, depletion and amortization		20,357			38,105(2	)		29,131(8	)		88,941(12	)		176,534
General and administrative expenses		4,361			13,314(3	)		—			6,750(13	)		24,425
Derivative losses and accretion of
asset retirement obligation		806			2,214(4	)		644(4	)		2,430(4	)		6,094
Interest income		(5,000	)		5,000(5	)		—			-			-
Interest expense		7,933			23,799(6	)		23,249(9	)		39,119(14	)		94,100
Income before income taxes		8,669			(6,599	)		(5,139	)		(26,360	)		(29,429	)
Income tax expense (benefit)		1,727			(2,331)(15	)		(1,816)(15	)		(9,313)(15	)		(11,733	)
Net income (loss)	$	6,942		$	(4,268	)	$	(3,323	)	$	(17,047	)	$	(17,696	)
Earnings per share - Bais (16)	$	0.14											$	(0.21	)
Earnings per share - Diluted (16)	$	0.12											$	(0.21	)

(1) To reflect Marlin historical revenues and operating expenses for the period July 1, 2005 to April 3, 2006.

(2) To reflect additional Marlin depreciation, depletion and amortization for production from July 1, 2005 to April 3, 2006 and adjust Energy XXI’s historical depreciation, depletion and amortization (total combined production of 1,567,455 BOE) based on a pro forma combined depreciation, depletion and amortization rate of $24.31 per BOE.

(3) To reflect additional general and administrative expenses for both the Marlin and Castex acquisitions based on annualizing the Company’s actual general and administrative expenses for the period April 4, 2006 to June 30, 2006. Incremental general and administrative expenses associated with the Castex acquisition were not significant.

(4) To reflect additional asset retirement obligation accretion for Marlin ($2,214), Castex ($644) and Pogo ($2,430).

(5) To eliminate interest income on cash that was used to fund the Marlin acquisition.

(6) To record additional interest expense related to the Marlin acquisition by annualizing the Company’s interest expense for the period April 4, 2006 to June 30, 2006.

(7) To reflect Castex historical revenue and direct operating expenses for the period July 1, 2005 to June 30, 2006.

F-65

ENERGY XXI (BERMUDA) LIMITED

PRO FORMA INCOME STATEMENT

PERIOD FROM JULY 25, 2005 (INCEPTION) TO JUNE 30, 2006

(Unaudited)

(8) To reflect additional depreciation, depletion and amortization associated with historical Castex production of 1,198,318 BOE using a combined depreciation, depletion and amortization rate of $24.31 per BOE.

(9) To reflect additional interest expense associated with the Castex acquisition based on incremental borrowings of $229,000 at an interest rate of 8.6% and $3,555 of amortization of incremental debt issue costs associated with the Castex acquisition combined with the write-off of debt issue cost associated with the previous facility.

(10) To reflect the historical revenue and operating expenses of Pogo for the period from July 1, 2005 to June 30, 2006.

(11) To reflect additional wind storm insurance premiums of $10 million annually related to the Pogo assets.

(12) To reflect additional Pogo depreciation, depletion and amortization for production from July 1, 2005 to June 30, 2006 based on Pogo’s actual production volumes for the period July 1, 2005 to June 30, 2006 of 2,683,532 BOE at the estimated pro forma depreciation, depletion and amortization rate of $24.31 per BOE, to adjust Energy XXI’s historical production to the $24.31 per BOE rate and to record additional DD&A on other property and equipment.

(13) To reflect incremental general and administrative expenses expected to be incurred as a result of the Pogo acquisition of $9 million annually, less 25% which is expected to be capitalized related directly to property acquisition, exploration and development activities.

(14) To reflect additional interest expense associated with the Pogo acquisition for the period July 1, 2005 through June 30, 2006 based on a 10% interest rate on $750 million of New Senior Notes, a 7% interest rate on the revolving credit facility, 7.1% on all additional borrowings and $2.9 million of amortization of debt issue costs associated with the Pogo acquisition.  Interest expense excludes non-recurring expenses of $8.1 million ($5.3 million net of tax) related to the refinancing of the Company’s revolving credit facility.

(15) To reflect income tax benefit of 35.33% of the pro forma pre tax loss.

(16) The basic and diluted weighted average shares of stock outstanding for the year ended June 30, 2006 were 84,049,115.

F-66

ENERGY XXI (BERMUDA) LIMITED

PRO FORMA RESERVE INFORMATION

PERIODS ENDED JUNE 30, 2006, 2005 AND 2004

Estimated net Quantities of Oil and Natural Gas Reserves

The following pro forma estimates of net proved oil and gas reserves reflect the acquisition of Marlin, Castex and the POGO properties beginning July 1, 2003, located entirely within the United States of America, are based on evaluations prepared by the Company and third-party engineers. Reserves were estimated in accordance with guidelines established by the SEC and FASB which require that reserve estimates be prepared under existing economic and operating conditions. Reserve estimates are inherently imprecise and accordingly, reserve estimates are expected to change as additional performance data becomes available.

MARLIN	OIL MBBLS			GAS MMCF
June 30, 2003		1,864			34,421
Purchases (sales) of minerals in place		11,788			45,174
Extensions, discoveries, improved recovery and other additions		780			10,050
Production		(555	)		(9,625	)
June 30, 2004		13,877			80,020
Extensions, discoveries, improved recovery and other additions		890			5,946
Production		(1,290	)		(10,104	)
June 30, 2005		13,477			75,862
Extensions, discoveries, improved recovery and other additions		694			2,862
Revisions to previous estimates		1,435			(4,626	)
Production		(1,785	)		(9,446	)
June 30, 2006		13,821			64,652

CASTEX	OIL MBBLS		GAS MMCF
June 30, 2003	23		129
Extensions, discoveries, improved recovery and other additions	63		2,502
Revisions to previous estimates	4		57
Production	(4	)	(11	)
June 30, 2004	86		2,677
Extensions, discoveries, improved recovery and other additions	40		2,412
Revisions to previous estimates	48		589
Production	(46	)	(550	)
June 30, 2005	128		5,128
Purchases (sales) of minerals in place	1,176		70,319
Extensions, discoveries, improved recovery and other additions	22		1,162
Production	(150	)	(6,290	)
June 30, 2006	1,176		70,319

F-67

POGO PROPERTIES	OIL MBBLS			GAS MMCF
June 30, 2003		21,249			65,157
Extensions, discoveries, improved recovery and other additions		117			529
Revisions to previous estimates		889			(555	)
Production		(3,634	)		(9,207	)
June 30, 2004		18,621			55,924
Purchases (sales) of minerals in place		1,592			4,274
Extensions, discoveries, improved recovery and other additions		227			2,040
Revisions to previous estimates		765			(1,510	)
Production		(3,444	)		(8,456	)
June 30, 2005		17,761			52,272
Extensions, discoveries, improved recovery and other additions		208			1,998
Revisions to previous estimates		1,085			(2,851	)
Production		(2,761	)		(7,175	)
June 30, 2006		16,293			44,244

PRO FORMA	OIL MBBLS			GAS MMCF
June 30, 2003		23,136			99,707
Purchases (sales) of minerals in place		11,788			45,174
Extensions, discoveries, improved recovery and other additions		960			13,081
Revisions to previous estimates		893			(498	)
Production		(4,193	)		(18,843	)
June 30, 2004		32,584			138,621
Purchases (sales) of minerals in place		1,592			4,274
Extensions, discoveries, improved recovery and other additions		1,157			10,398
Revisions to previous estimates		813			(921	)
Production		(4,780	)		(19,110	)
June 30, 2005		31,366			133,262
Purchases (sales) of minerals in place		1,176			70,319
Extensions, discoveries, improved recovery and other additions		924			6,022
Revisions to previous estimates		2,520			(7,477	)
Production		(4,696	)		(22,911	)
June 30, 2006		31,290			179,215

F-68

PRO FORMA STANDARDIZED MEASURE

A summary of the pro forma standardized measure of discounted future net cash flows relating to proved 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 the Company’s existing proved oil and natural gas reserves.

Pro Forma June 30,	2006		2005		2004
	(In millions)
Future cash inflows	$	3,301	$	2,706	$	1,812
Less related future
Production costs		704		596		398
Development costs		476		258		149
Income taxes		545		517		366
Future net cash flows		1,576		1,335		899
10% annual discount for estimated timing of cash flows		410		348		220
Standardized measure of discounted future net cash flows	$	1,166	$	987	$	679

A summary of the pro forma changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves follows.

Pro Forma Year Ended June 30,	2006			2005			2004
	(In millions)
Beginning of fiscal year,	$	987		$	679		$	469
Sales and transfers		(547	)		(390	)		(220	)
Net changes in prices		252			631			188
Extensions		54			90			45
Revisions		120			(3	)		(43	)
Accretion		90			64			45
Change in taxes		(10	)		(135	)		(51	)
Purchases (sales)		323			78			222
Development costs and other		(103	)		(27	)		24
End of fiscal year,	$	1,166		$	987		$	679

F-69

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

The following table sets forth an itemization of all estimated expenses, all of which we will pay, in connection with the issuance and distribution of the securities being registered:

SEC registration fee	$	7,256
Legal fees and expenses	$	50,000
Accounting fees and expenses	$	20,000
Miscellaneous	$	30,000
Total	$	107,256

Item 14. Indemnification of Directors and Officers

Our bye-laws provide for indemnification of our officers and directors against all liabilities, loss, damage or expense incurred or suffered by any officer or director in his or her role as an officer or director of us to the maximum extent permitted by Bermuda law. However, the indemnification does not extend to any matter which would render it void pursuant to the Companies Act 1981 as in effect from time to time in Bermuda.

The Companies Act provides that a Bermuda company may indemnify its officers and directors in respect of any loss arising or liability attaching to them as a result of any negligence, default, breach of duty or breach of trust of which they may be guilty. A company is also permitted to indemnify any officer or director against any liability incurred by him or her in defending any proceedings, whether civil or criminal, in which judgment is given in favor of the director or officer, or in which he or she is acquitted, or in connection with any application under relevant Bermuda legislation in which relief from liability is granted to him or her by the court. However, the Companies Act also states that any provision, whether contained in our bye-laws or in a contract or arrangement between us and the officer or director, indemnifying an officer or director against any liability which would attach to him in respect of his or her fraud or dishonesty will be void.

Our directors and officers also are covered by directors’ and officers’ insurance policies maintained by us.

Our bye-laws provide that each shareholder agrees to waive any claim or right of action he or she may have, whether individually or by or in the right of us, against any of our officers or directors on account of any action taken by any officer or director, or the failure of any officer or director to take any action in the performance of his or her duties with or for us; provided, however, that this waiver does not apply to any claims or rights of action arising out of the fraud or dishonesty of an officer or a director, or to recover any gain, personal profit or advantage to which an officer or director is not legally entitled.

Item 15. Recent Sales of Unregistered Securities

Since July 25, 2005 (inception), we sold and issued the unregistered securities described below. We believe that each of the securities transactions was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2) as a transaction not involving any public offering and Regulation D.

On July 25, 2005, we issued 12.5 million shares to officers, directors and other affiliated entities in conjunction with our formation. On October 20, 2005, we issued 50 million shares in an initial public offering (IPO) on the “Alternative Investment Market” of the London Stock Exchange. Approximately 3.5 million of the IPO shares were subsequently repurchased by us on April 4, 2006 for $5.60 per share from various holders in privately negotiated transactions, and then resold in a private placement on April 21, 2006 for $5.60 per share.

II-1

No underwriters were used to effect this transaction. In June, July and August 2006, we issued an additional 18.2 million, 3.2 million and 60,000 shares, respectively, related to the conversion of some of our outstanding warrants.

The proceeds from all of the sales listed above were used for general corporate purposes.

On April 24, 2007, we issued 3.98 million shares to Pogo Producing Company ("Pogo") as a deposit under the Purchase and Sale Agreement entered into by our subsidiary, Energy XXI GOM, LLC, and Pogo. On June 8, 2007 the transactions contemplated by this agreement were completed and the shares were returned to us and cancelled. The issuance of such shares of common stock was exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"), under Section 4(2) of the Securities Act on the basis that it did not involve a public offering. We did not receive any proceeds from the issuance of these shares.

On February 6, 2007, we purchased 500,000 warrants from Forrest Nominees a the total consideration of $437,500 ($0.875 per warrant). The acquired warrants were cancelled and our total outstanding warrants (after giving effect to the purchase) was 77,389,872.

Item 16. Exhibits and Financial Statement Schedules

3.1	Certificate of Incorporation
3.2	Certificate of Incorporation on Change of Name
3.3	Certificate of Deposit of Memorandum of Increase of Share Capital
3.4	Altered Memorandum of Association
3.5	Bye-Laws
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.
5.1	Opinion of Appleby Hunter Bailhache.
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.

II-2

Table of Contents

Index to Financial Statements

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.
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
21.1	Subsidiary List
23.1	Consent of UHY LLP (Energy XXI)
23.2	Consent of UHY LLP (Castex)
23.3	Consent of UHY LLP (Pogo)
23.4	Consent of Grant Thornton LLP
23.5	Consent of Netherland, Sewell & Associates, Inc.
23.6	Consent of Miller and Lents, Ltd.
23.7	Consent of Ryder Scott Company, LP

II-3

Item 17. Undertakings

The undersigned Registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this Registration Statement:

(i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933, as amended (the “Securities Act”);

(ii) To reflect in the prospectus any facts or events arising after the effective date of the Registration Statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the Registration Statement;

(iii) To include any material information with respect to the plan of distribution not previously disclosed the Registration Statement or any material change to such information in the Registration Statement;

(2) That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser:

i. If the registrant is relying on Rule 430B:

A. Each prospectus filed by the registrant pursuant to Rule 424(b)(3) shall be deemed to be part of the registration statement as of the date the filed prospectus was deemed part of and included in the registration statement; and

B. Each prospectus required to be filed pursuant to Rule 424(b)(2), (b)(5), or (b)(7) as part of a registration statement in reliance on Rule 430B relating to an offering made pursuant to Rule 415(a)(1)(i), (vii), or (x) for the purpose of providing the information required by section 10(a) of the Securities Act of 1933 shall be deemed to be part of and included in the registration statement as of the earlier of the date such form of prospectus is first used after effectiveness or the date of the first contract of sale of securities in the offering described in the prospectus. As provided in Rule 430B, for liability purposes of the issuer and any person that is at that date an underwriter, such date shall be deemed to be a new effective date of the registration statement relating to these securities in the registration statement to which that prospectus relates, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such effective date, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such effective date; or

ii. If the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness.

II-4

Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(5) That, for purposes of determining any liability under the Securities Act, each filing of the registrant’s annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be initial bona fide offering thereof.

(6) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or controlling persons pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

II-5

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, in the State of Texas on June 26, 2007.

ENERGY XXI (BERMUDA) LIMITED
By:	/s/ JOHN D. SCHILLER, JR.
	John D. Schiller, Jr. Chairman and Chief Executive Officer (Principal Executive Officer)

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons in the capacities and on the dates indicated below.

Signature	Title	Date
/s/    STEVEN A. WEYEL         Steven A. Weyel	Director, President and Chief Operating Officer	June 26, 2007
/s/    DAVID WEST GRIFFIN         David West Griffin	Director, Chief Financial Officer (Principal Financial Officer)	June 26, 2007
/s/    HUGH A. MENOWN Hugh A. Menown	Chief Accounting Officer (Principal Accounting Officer)	June 26, 2007
/s/    WILLIAM COLVIN          William Colvin	Director	June 26, 2007
/s/    DAVID M. DUNWOODY          David M. Dunwoody	Director	June 26, 2007

/s/    HILL A. FEINBERG Hill A. Feinberg Director June 26, 2007

/s/    PAUL DAVISON  Paul Davison Director June 26, 2007

II-6

EXHIBIT INDEX

Copies of the following documents are included as exhibits to this registration statement.

3.1	Certificate of Incorporation
3.2	Certificate of Incorporation on Change of Name
3.3	Certificate of Deposit of Memorandum of Increase of Share Capital
3.4	Altered Memorandum of Association
3.5	Bye-Laws
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.
5.1	Opinion of Appleby Hunter Bailhache.
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.

64

Table of Contents

Index to Financial Statements

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.
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
21.1	Subsidiary List
23.1	Consent of UHY LLP (Energy XXI)
23.2	Consent of UHY LLP (Castex)
23.3	Consent of UHY LLP (Pogo)
23.4	Consent of Grant Thornton LLP
23.5	Consent of Netherland, Sewell & Associates, Inc.
23.6	Consent of Miller and Lents, Ltd.
23.7	Consent of Ryder Scott Company, LP

65