As filed with the Securities and Exchange Commission on August 22, 2007

Registration No. 333-        

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

FORM S-4

 

REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933

 

Energy XXI Gulf Coast, Inc.*

(Exact Name of Registrant as Specified in its Charter)

Delaware	1311	20-4278595
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1021 Main, Suite 2626
Houston, Texas 77002
(713) 351-3000

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

Ben Marchive
President
1021 Main, Suite 2626
Houston, Texas 77002
(713) 351-3000

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

Copies to:

Vinson & Elkins L.L.P.
First City Tower, Suite 2300
Houston, Texas 77002
(713) 758-2222
Attn: T. Mark Kelly

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) 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. o

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 registration statement for the same offering. o

*Includes certain registrant guarantors identified on the following page.

 

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 Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered		Proposed Maximum Offering Price Per Note(1)			Proposed Maximum Aggregate Offering Price (1)		Amount of Registration Fee(2)
10% Senior Notes due 2013	$	750,000,000		100	%	$	750,000,000	$	23,025
Guarantees of 10% Senior Notes due 2013(3)		(4)		(4)			(4)		(5)

(1) Estimated solely for the purpose of calculating the registration fee pursuant to rule 457(f)(2) of the rules and regulations under the Securities Act.

(2) Calculated by multiplying the aggregate offering amount by 0.00003076.

(3) See below for table of registrant guarantors.

(4) No separate consideration will be received for the guarantees.

(5) No further fee is payable pursuant to Rule 457(n) of the rules and regulations under the Securities Act.

ADDITIONAL GUARANTOR REGISTRANTS

Exact Name of Additional Registrant as Specified in its Charter	State or Other Jurisdiction of Incorporation or Organization		Primary Standard Industrial Classification Code Number		IRS Employee Identification No.
Energy XXI (Bermuda) Limited		Bermuda		1311		98-0499286
Energy XXI Texas, LP		Delaware		1311		20-0650308
Energy XXI Texas GP, LLC		Delaware		1311		20-0650294
Energy XXI GOM, LLC		Delaware		1311		56-2140027

The information in this prospectus is not complete and may be changed. We may not 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 state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED AUGUST 22, 2007

PROSPECTUS

$750,000,000

Energy XXI Gulf Coast, Inc.

Offer to Exchange up to
$750,000,000 of 10% Senior Notes due 2013
that have been registered under the Securities Act of 1933
for
$750,000,000 of 10% Senior Notes due 2013
that have not been registered under the Securities Act of 1933

The Exchange Offer will expire at 5:00 pm, New York City time,
on         , 2007, unless we extend the date

 

Terms of the Exchange Offer

• We are offering to exchange up to $750.0 million aggregate principal amount of registered 10% Senior Notes due 2013, which we refer to as the new notes, for any and all of our $750.0 million aggregate principal amount of unregistered 10% Senior Notes due 2013, which we will refer to as the old notes, that were issued on June 8, 2007. The new notes are being issued under the indenture pursuant to which we previously issued the old notes.

• We will exchange all outstanding old notes that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer for an equal principal amount of new notes.

• The terms of the new notes are substantially identical to those of the outstanding old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes.

• You may withdraw tenders of old notes at any time prior to the expiration of the exchange offer.

• The exchange of new notes for old notes should not be a taxable transaction for U.S. federal income tax purposes.

• We will not receive any cash proceeds from the exchange offer.

• The old notes are, and the new notes will be, guaranteed by each of our existing subsidiaries, our future material domestic restricted subsidiares and by Energy XXI (Bermuda) Limited, our ultimate parent company.

This investment involves risks. Please read “Risk Factors” beginning on page 9 for a discussion of the risks that you should consider prior to tendering your outstanding old notes in the exchange offer.

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

 

The date of this prospectus is         , 2007.

This prospectus incorporates by reference important business and financial information about us that is not included in or delivered with this document. This information is available to you without charge upon written or oral request to: Energy XXI Gulf Coast, Inc., 1021 Main, Suite 2626, Houston, Texas 77002, Attention: Corporate Secretary, (713) 531-3000. To obtain timely delivery, you must request the information no later than         , 2007, which is five business days before the expiration date of this exchange offer.

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, referred to in this prospectus as the SEC. In making your decision to participate in the exchange offer, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. If you received any unauthorized information, you must not rely on it. We are not making an offer to sell these securities in any state or jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus, or the documents incorporated by reference into this prospectus, is accurate as of any date other than the date on the front cover of this prospectus or the date of such document incorporated by reference, as the case may be.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. Please read “Plan of Distribution.”

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TABLE OF CONTENTS

	Page
Prospectus Summary		1
Risk Factors		9
Ratio of Earnings to Fixed Charges		25
Use of Proceeds		25
The Exchange Offer		26
Cautionary Statement Concerning Forward-Looking Statements		36
Selected Financial Information of Energy XXI Gulf Coast, Inc.		37
Management’s Discussion and Analysis of Financial Condition and Results of Operations		39
Business		51
Properties		63
Security Ownership of Certain Beneficial Owners and Management		66
Directors and Officers		68
Executive Compensation		72
Certain Relationships and Related Transactions		87
Legal Proceedings		87
Market Price of Common Stock and Related Matters		88
Description of the New Notes		89
Certain United States Federal Income Tax Considerations		133
Plan of Distribution		133
Legal Matters		133
Independent Registered Public Accounting Firms		134
Independent Petroleum Engineers		134
Where You Can Find More Information		134
Index to Financial Statements		F-1

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PROSPECTUS SUMMARY

This following summary highlights selected information from the prospectus and may not contain all of the information that is important to you. This prospectus includes specific terms of the new notes, as well as information regarding our business and financial data. Before making an investment decision, you should read this entire prospectus carefully, including the section entitled “Risk Factors”, for a more detailed description of our business. In this prospectus, “Energy XXI,” “the Company,” “we,” “us” and “our” refer to Energy XXI Gulf Coast, Inc., the issuer of the notes, and its subsidiaries on a consolidated basis.

The Company

We are a Houston-based 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. Our parent, Energy XXI (Bermuda) Limited (our “Parent”), completed a $300 million initial public offering of common stock and warrants on the Alternative Investment Market (“AIM”) of the London Stock Exchange in October 2005. Since our formation, 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.

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.

Our exploration and production activities commenced in April 2006 upon our Parent’s 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

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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.

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.

We are a Delaware corporation, and our executive offices are located at 1021 Main, Suite 2626, Houston, Texas 77002 and our telephone number is (713) 351-3000. Our website is located at http://www.energyxxi.com. The information on our website is not part of this prospectus.

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The Exchange Offer

On June 8, 2007, we completed a private offering of $750 million in aggregate principal of the old notes. As part of this private offering, we entered into a registration rights agreement with the initial purchasers of the old notes in which we agreed, among other things, to deliver this prospectus to you and to use our best efforts to complete the exchange offer. The following is a summary of the exchange offer.

Old Notes

10% Senior Notes due 2013, which were issued on June 8, 2007.

New Notes

10% Senior Notes due 2013. The terms of the new notes are substantially identical to those terms of the outstanding old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes.

Exchange Offer

We are offering to exchange up to $750.0 million aggregate principal amount of our new notes that have been registered under the Securities Act for an equal amount of our outstanding old notes that have not been registered under the Securities Act to satisfy our obligations under the registration rights agreements.

The new notes will evidence the same debt as the old notes and will be issued under and be entitled to the benefits of the same indenture that governs the old notes. Holders of the old notes do not have any appraisal or dissenter rights in connection with the exchange offer. Because the new notes will be registered, the new notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their old notes accepted in the exchange offer will have no registration rights.

Expiration Date.

The exchange offer will expire at 5:00 p.m., New York City time, on       , 2007, unless we decide to extend it.

Conditions to the Exchange Offer.

The exchange offer is subject to customary conditions, which we may waive. Please read “The Exchange Offer — Conditions to the Exchange Offer” for more information regarding the conditions to the exchange offer.

Procedures for Tendering Old
Notes.

Unless you comply with the procedures described under the caption “The Exchange Offer — Procedures for Tendering — Guaranteed Delivery,” you must do one of the following on or prior to the expiration of the exchange offer to participate in the exchange offer:

•  

tender your old notes by sending the certificates for your old notes, in proper form for transfer, a properly completed and duly executed letter of transmittal, with any required signature guarantees, and all other documents required by the letter of transmittal, to Wells Fargo Bank, National Association, as registrar and exchange agent, at the address listed under the caption “The Exchange Offer — Exchange Agent”; or

•  

tender your old notes by using the book-entry transfer procedures described below and transmitting a properly completed and duly executed letter of transmittal, with any required signature guarantees, or an agent’s message instead of the letter of transmittal, to the exchange agent. In order for a book-entry transfer to constitute a valid tender of your old

3

notes in the exchange offer, Wells Fargo Bank, National Association, as registrar and exchange agent, must receive a confirmation of book-entry transfer of your old notes into the exchange agent’s account at The Depository Trust Company prior to the expiration of the exchange offer. For more information regarding the use of book-entry transfer procedures, including a description of the required agent’s message, please read the discussion under the caption “The Exchange Offer — Procedures for Tendering — Book-Entry Transfer.”

Guaranteed Delivery Procedures

If you are a registered holder of the old notes and wish to tender your old notes in the exchange offer, but

•  

the old notes are not immediately available,

•  

time will not permit your old notes or other required documents to reach the exchange agent before the expiration of the exchange offer, or

•  

the procedure for book-entry transfer cannot be completed prior to the expiration of the exchange offer,

then you may tender old notes by following the procedures described under the caption “The Exchange Offer — Procedures for Tendering — Guaranteed Delivery.”

Special Procedures for Beneficial Owners.

If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your old notes in the exchange offer, you should promptly contact the person in whose name the old notes are registered and instruct that person to tender on your behalf.

If you wish to tender in the exchange offer on your own behalf, prior to completing and executing the letter of transmittal and delivering the certificates for your old notes, you must either make appropriate arrangements to register ownership of the old notes in your name or obtain a properly completed bond power from the person in whose name the old notes are registered.

Withdrawal; Non-Acceptance

You may withdraw any old notes tendered in the exchange offer at any time prior to 5:00 p.m., New York City time, on       , 2007. If we decide for any reason not to accept any old notes tendered for exchange, the old notes will be returned to the registered holder at our expense promptly after the expiration or termination of the exchange offer. In the case of old notes tendered by book-entry transfer into the exchange agent’s account at The Depository Trust Company, any withdrawn or unaccepted old notes will be credited to the tendering holder’s account at The Depository Trust Company. For further information regarding the withdrawal of tendered old notes, please read “The Exchange Offer — Withdrawal Rights.”

U.S. Federal Income Tax
Considerations.

The exchange of new notes for old notes in the exchange offer should not be a taxable event for U.S. federal income tax purposes. Please read the discussion under the caption “Material U.S. Federal

4

Income Tax Considerations” for more information regarding the tax consequences to you of the exchange offer.

Use of Proceeds.

The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement.

Fees and Expenses

We will pay all of our expenses incident to the exchange offer.

Exchange Agent

We have appointed Wells Fargo Bank, National Association as exchange agent for the exchange offer. You can find the address, telephone number and fax number of the exchange agent under the caption “The Exchange Offer — Exchange Agent.”

Resales of New Notes.

Based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties that are not related to us, we believe that the new notes you receive in the exchange offer may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act so long as:

•  

the new notes are being acquired in the ordinary course of business;

•  

you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the new notes issued to you in the exchange offer;

•  

you are not our affiliate; and

•  

you are not a broker-dealer tendering old notes acquired directly from us for your account.

The SEC has not considered this exchange offer in the context of a no-action letter, and we cannot assure you that the SEC would make similar determinations with respect to this exchange offer. If any of these conditions are not satisfied, or if our belief is not accurate, and you transfer any new notes issued to you in the exchange offer without delivering a resale prospectus meeting the requirements of the Securities Act or without an exemption from registration of your new notes from those requirements, you may incur liability under the Securities Act. We will not assume, nor will we indemnify you against, any such liability. Each broker-dealer that receives new notes for its own account in exchange for old notes, where the old notes were acquired by such broker-dealer as a result of market-making or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of Distribution.”

Please read “The Exchange Offer — Resales of New Notes” for more information regarding resales of the new notes.

Consequences of Not Exchanging Your Old Notes.

If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register your old notes under the Securities Act, except in the limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer your old notes

5

unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

For information regarding the consequences of not tendering your old notes and our obligation to file a registration statement, please read “The Exchange Offer — Consequences of Failure to Exchange Outstanding Securities” and “Description of the New Notes.”

Description of the New Notes

The terms of the new notes and those of the outstanding old notes are substantially identical, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. As a result, the new notes will not bear legends restricting their transfer and will not have the benefit of the registration rights and special interest provisions contained in the old notes. The new notes represent the same debt as the old notes for which they are being exchanged. Both the old notes and the new notes are governed by the same indenture.

The following is a summary of the terms of the new notes. It may not contain all the information that is important to you. For a more detailed description of the new notes, please read “Description of the New Notes.”

Issuer

Energy XXI Gulf Coast, Inc.

Securities Offered

$750,000,000 aggregate principal amount of 10% Senior Notes due 2013. The new notes are being offered as additional debt securities under the indenture pursuant to which we previously issued the old notes.

Interest

Interest on the new notes will accrue at the rate of 10% per year and will be payable semi-annually in arrears on each June 15 and December 15, commencing on December 15, 2007.

Maturity Date

The new notes will mature on June 15, 2013.

Guarantees

The new notes will be guaranteed by each of our existing subsidiaries and future material domestic restricted subsidiaries and Energy XXI (Bermuda) Limited, our ultimate parent company (“Parent”). See “Description of the Notes — Brief Description of the Notes and the Guarantees — The Guarantees.” Although the notes will be guaranteed by Parent, Parent will generally not be subject to the restrictive covenants in the indenture governing the notes.

Use of Proceeds

The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement.

Ranking

The new notes and the guarantees will be our and the guarantors’ senior unsecured obligations and will rank equal in right of payment to all of our and the guarantors’ existing and future senior indebtedness and will be effectively subordinated to our and the guarantors’ existing and future secured indebtedness to the extent of the collateral therefor.

As of March 31, 2007, after giving effect to the Pogo Acquisition, the related $750 million offering of the old notes and the repayment of our second lien revolving credit facility, all of which occurred on June 8, 2007 and to which we collectively refer to as the “Transactions”, we and the subsidiary guarantors would have had

6

$978.5 million of total debt outstanding, of which $228.5 million was secured and effectively senior to the notes to the extent of the value of the collateral, and Parent, which will guarantee the notes, would have had no senior debt outstanding. In addition, as of March 31, 2007, after the Transactions we would be able to incur approximately $201.5 million of additional indebtedness under the borrowing base limitations of our first lien revolving credit facility, including a $5.0 million outstanding letter of credit.

Optional Redemption

On or after June 15, 2010, we will have the right to redeem all or part of the new notes at a redemption price that will decrease ratably from 105% of the aggregate principal amount to 100% of the aggregate principal amount on or after June 15, 2012, in each case plus accrued and unpaid interest. Prior to June 15, 2010, we may redeem up to 35% of the aggregate principal amount of the new notes originally issued at a price equal to 110% of the aggregate principal amount plus accrued and unpaid interest with the proceeds of certain equity offerings. In addition, prior to June 15, 2010, we may redeem all or part of the new notes at a price equal to 100% of the aggregate principal amount plus a make-whole premium and accrued and unpaid interest.

Change of Control Offer

If a change of control, as defined in the indenture, occurs, each holder of new notes will have the right to require us to repurchase all or any part of their new notes at a price equal to 101% of their principal amount plus accrued and unpaid interest.

Asset Sale Proceeds

If we engage in certain asset sales, we generally must either invest the net cash proceeds from such sales in our business within a period of time, repay the debt under our first lien revolving credit facility or make an offer to purchase a principal amount of the new notes equal to the excess net cash proceeds. The purchase price of each new note so purchased will be 100% of its principal amount plus accrued and unpaid interest.

Certain Covenants

The indenture governing the new notes will, among other things, limit our ability and the ability of our restricted subsidiaries to:

•  

transfer or sell assets;

•  

make investments;

•  

pay dividends, redeem subordinated indebtedness or make other restricted payments;

•  

incur or guarantee additional indebtedness or issue disqualified capital stock;

•  

create or incur liens;

•  

incur dividend or other payment restrictions affecting certain subsidiaries;

•  

consummate a merger, consolidation or sale of all or substantially all of our assets;

•  

enter into transactions with affiliates; and

•  

engage in businesses other than the oil and gas business.

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With limited exceptions, the Parent will not be subject to these covenants.

Transfer Restrictions

The new notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the new notes.

Risk Factors

Investing in the new notes involves substantial risk. Please read “Risk Factors” beginning on page 9 for a discussion of certain factors you should consider in evaluating an investment in the new notes.

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RISK FACTORS

In addition to the other information set forth elsewhere in this prospectus, the following factors relating to our company, the exchange offer and the new notes should be considered carefully in deciding whether to participate in the exchange offer.

Risks Related to the Exchange Offer and the New Notes

If you do not properly tender your old notes, you will continue to hold unregistered outstanding notes and your ability to transfer outstanding notes will be adversely affected.

We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes. Please read “The Exchange Offer — Procedures for Tendering” and “Description of the New Notes.”

If you do not exchange your old notes for new notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your old notes described in the legend on the certificates for your old notes. In general, you may only offer or sell the old notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. We do not plan to register any sale of the old notes under the Securities Act. For further information regarding the consequences of tendering your old notes in the exchange offer, please read “The Exchange Offer — Consequences of Failure to Exchange Outstanding Securities.”

You may find it difficult to sell your new notes.

Although the new notes will trade in The PORTAL^(SM) Market and will be registered under the Securities Act, the new notes will not be listed on any securities exchange. Because there is no public market for the new notes, you may not be able to resell them.

We cannot assure you that an active market will exist for the new notes or that any trading market that does develop will be liquid. If an active market does not develop or is not maintained, the market price and liquidity of our new notes may be adversely affected. If a market for the new notes develops, they may trade at a discount from their initial offering price. The trading market for the notes may be adversely affected by:

• changes in the overall market for non-investment grade securities;

• changes in our financial performance or prospects;

• the financial performance or prospects for companies in our industry generally;

• the number of holders of the notes;

• the interest of securities dealers in making a market for the notes; and

• prevailing interest rates and general economic conditions.

Historically, the market for non-investment grade debt has been subject to substantial volatility in prices. The market for the new notes, if any, may be subject to similar volatility. Prospective investors in the new notes should be aware that they may be required to bear the financial risks of such investment for an indefinite period of time.

Some holders who exchange their old notes may be deemed to be underwriters.

If you exchange your old notes in the exchange offer for the purpose of participating in a distribution of the new notes, you may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

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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.

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

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

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

Risks Associated with Acquisitions and our Risk Management Program

Our acquisitions may be stretching our existing resources.

Since our inception in February 2006, we have made three major acquisitions and our Parent has 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.

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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;

• 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

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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.

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

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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;

• 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.

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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.

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

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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

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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.

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.

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

Other Risks

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

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

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

Our success will depend to a significant extent upon the efforts and abilities of our and our Parent’s 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 our 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.

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Risks Related to the Notes

The notes and the guarantees will be structurally subordinated to our and the guarantors’ secured debt to the extent of the value of the collateral securing the debt.

The indebtedness evidenced by the notes will be our senior unsecured obligations. The notes will rank equal in right of payment with all of our existing and future senior indebtedness and senior to all of our existing and future subordinated indebtedness. However, the notes will be structurally subordinated to all of our existing and future secured indebtedness, including our obligations under the first lien revolving credit facility, to the extent of the value of the assets securing such secured indebtedness. Debt outstanding under our first lien revolving credit facility (including hedges entered into in connection herewith) will be secured by a first priority security interest, subject to certain exceptions, in substantially all of our assets and, through secured guarantees, the assets of our subsidiaries.

The indebtedness evidenced by the subsidiary guarantees and the Parent guarantee will be senior unsecured indebtedness of the applicable guarantor. Such guarantees will rank equal in right of payment with all existing and future senior indebtedness of such guarantor, and senior to all existing and future subordinated indebtedness of such guarantor. The guarantees will also be effectively subordinated to any secured indebtedness of such guarantor, including the obligations of such guarantor under our first lien revolving credit facility (including hedges entered into in connection herewith), to the extent of the value of the assets securing such secured indebtedness.

In the event of a bankruptcy, liquidation, reorganization or other winding up involving us or any of our subsidiaries, a default in the payment under our first lien revolving credit facility, the notes or an acceleration of any debt under our first lien revolving credit facility (including hedges entered into in connection herewith) or the notes, the holders of the secured debt could have the right to foreclose on their collateral to the exclusion of the holders of the notes even if an event of default were then to exist under the indenture governing the notes. Upon the occurrence of any of these events, there may not be sufficient funds to pay amounts due on the notes.

We are dependent on the earnings of our subsidiaries to make payments on the notes.

A substantial portion of our assets consist of direct and indirect ownership interests in our subsidiaries. Our subsidiaries are legally distinct from us and have no obligation to pay amounts due on our debt or to make funds available to us for such payment. Consequently, our ability to repay our debt, including the notes, depends to a large extent on the earnings of our subsidiaries, our ability to receive funds from such subsidiaries through dividends, repayment of intercompany notes or other payments and from our investments in cash and marketable securities. The ability of our subsidiaries to pay dividends, repay intercompany notes or make other advances to us is subject to restrictions imposed by applicable laws, tax considerations and the terms of agreements governing our subsidiaries. In addition, such payment may be restricted by claims against our subsidiaries by their creditors, including suppliers, vendors, lessors and employees.

We may not be able to purchase the notes upon a change of control or an offer to repurchase the notes in connection with an asset sale as required by the indenture.

Upon the occurrence of specific types of change of control events, we will be required to offer to repurchase all of the notes at a price equal to 101% of the principal amount, plus accrued and unpaid interest up to, but not including the date of repurchase. In addition, in connection with certain asset sales, we will be required to offer to repurchase all of the notes at a price equal to 100% of the principal amount, plus accrued and unpaid interest up to but not including the date of repurchase. We may not have sufficient funds available to repurchase all of the notes tendered pursuant to any such offer and any other debt that would become payable upon a change of control or in connection with such an asset sale offer. Our failure to purchase the notes would be a default under the indenture, which would in turn trigger a default under the first lien revolving credit facility. In that event, we would need to cure or refinance the first lien revolving credit facility before making an offer to purchase. Additionally, the exercise by the holders of notes of their right to require us to repurchase the notes upon an asset sale could cause a default under our first lien revolving credit facility if we are then prohibited by the terms of the first lien revolving credit facility from making the asset sale offer under the indenture. In the event an asset sale occurs at a time when we are prohibited from purchasing notes,

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we could seek the consent of our senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If we do not obtain a consent or repay those borrowings, we will remain prohibited from purchasing notes. In that case, our failure to purchase tendered notes would constitute an event of default under the indenture, which could, in turn, constitute a default under the other indebtedness, including the first lien revolving credit agreement. A change of control (as defined under the first lien revolving credit facility) would also constitute a default under our first lien revolving credit facility. Upon any such default, the lenders may declare any outstanding obligations under the first lien revolving credit facility immediately due and payable. If such debt repayment were accelerated, we may not have sufficient funds to repurchase the notes and repay the debt. There can be no assurance that we would be able to refinance our indebtedness or, if a refinancing were to occur, that the refinancing would be on terms favorable to us.

In addition, agreements governing future senior indebtedness may contain prohibitions of certain events that would constitute a change of control or require such senior indebtedness to be repurchased or repaid upon a change of control. Moreover, the exercise by the holders of their right to require us to repurchase the notes could cause a default under such agreements, even if the change of control itself does not, due to the financial effect of such repurchase on us. Finally, our ability to pay cash to the holders upon a repurchase may be limited by our then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

The definition of change of control includes a phrase relating to the sale or other transfer of “all or substantially all” of the properties or assets of the Parent and its subsidiaries, taken as a whole, us or any of our restricted subsidiaries taken as a whole. There is no precise definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty in ascertaining whether a particular transaction would involve a disposition of “all or substantially all” of the assets of any of the companies in question, and therefore it may be unclear as to whether a change of control has occurred and whether the holders of the notes have the right to require us to repurchase such notes.

Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the notes.

As of March 31, 2007, after giving effect to the Transactions, we and the subsidiary guarantors would have had $978.5 million of total debt outstanding. Our high level of indebtedness could have important consequences to you, including the following:

• it may make it difficult for us to satisfy our obligations under the notes and our other indebtedness and contractual and commercial commitments;

• prevent us from raising the funds necessary to repurchase notes tendered to us if there is a change of control, which would constitute a default under the indenture governing the notes and our first lien revolving credit facility; and

• it may otherwise limit us in the ways summarized above under “Risks Associated with Energy XXI Generally — Our indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities.”

Our ability to make payments with respect to the notes and to satisfy our other debt obligations will depend on our future operating performance, including our ability to realize the anticipated benefits from the Pogo Acquisition, and our ability to refinance our indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control.

Despite existing debt levels, we may still be able to incur substantially more debt, which would increase the risks associated with our leverage.

Even though we are highly leveraged, we may be able to incur substantial amounts of additional debt in the future, including debt under existing and future credit facilities, which may be secured and therefore structurally senior to the notes. As of March 31, 2007, after giving effect to the Transactions, we would be able to incur approximately $201.5 million of additional indebtedness under the borrowing base limitations of our first lien revolving credit facility, including a $5.0 million outstanding letter of credit. Although the terms of the notes and a future credit facility will limit our ability to incur additional debt, such terms do not and

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will not prohibit us from incurring substantial amounts of additional debt for specific purposes or under certain circumstances. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify. The incurrence of additional debt could adversely impact our ability to service payments on the notes.

We may not be able to generate sufficient cash flow to meet our debt service and other obligations due to events beyond our control.

Our ability to generate cash flows from operations and to make scheduled payments on our indebtedness will depend on our future financial performance. Our future performance will be affected by a range of economic, competitive and business factors that we cannot control, such as general economic and financial conditions in our industry or the economy generally. A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition or other events beyond our control could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service our debt and other obligations. If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as reducing capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital. We cannot assure you that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on the notes and our other indebtedness.

If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the notes. If the amounts outstanding under the first lien revolving credit facility or the notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders, including you as a noteholder.

The indenture governing the notes and the agreements governing our other indebtedness impose significant operating and financial restrictions on us and our subsidiaries that may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.

The indenture governing the notes will contain and our first lien revolving credit facility contains covenants that restrict our and our subsidiaries’ (but generally not our Parent’s) ability to take various actions, such as:

• engaging in businesses other than the oil and gas business;

• incurring or guaranteeing additional indebtedness or issuing disqualified capital stock;

• making investments;

• paying dividends, redeeming subordinated indebtedness or making other restricted payments;

• entering into transactions with affiliates;

• creating or incurring liens;

• transferring or selling assets;

• incurring dividend or other payment restrictions affecting certain subsidiaries;

• consummating a merger, consolidation or sale of all or substantially all our assets;

• entering into sale/leaseback transactions.

In addition, under our first lien revolving credit facility we expect there will be a restriction on changes in management.

We expect our first lien revolving credit facility will require, and any future credit facilities may require us to comply with specified financial ratios, including regarding interest coverage, total leverage, senior secured leverage coverage and fixed charge coverage.

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Our ability to comply with these covenants will likely be affected by events beyond our control and we cannot assure you that we will satisfy those requirements. A breach of any of these provisions could result in a default under these instruments, which could allow all amounts outstanding thereunder to be declared immediately due and payable, which would in turn trigger cross-acceleration and cross-default rights under our other debt. We may also be prevented from taking advantage of business opportunities that arise if we fail to meet certain ratios or because of the limitations imposed on us by the restrictive covenants under these instruments.

The restrictions contained in the indenture and first lien revolving credit facility could:

• limit our ability to plan for or react to market conditions, meet capital needs or otherwise restrict our activities or business plans; and

• adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.

Although the notes will be guaranteed by our Parent, our Parent will generally not be subject to the restrictive covenants in the indenture governing the notes.

In the event of a default under the first lien revolving credit facility, the lenders could foreclose on the assets and capital stock pledged to them.

A breach of any of the covenants contained in our first lien revolving credit facility, or in any future credit facilities, or our inability to comply with the financial ratios could result in an event of default, which would allow the lenders to declare all borrowings outstanding to be due and payable, which would in turn trigger an event of default under the indenture. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the notes. If the amounts outstanding under the first lien revolving credit facility or the notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders, including you as a noteholder.

A court could cancel the guarantees under fraudulent conveyance laws or certain other circumstances.

All of our present and future domestic restricted subsidiaries and Parent will guarantee the notes. If, however, such a guarantor becomes a debtor in a case under the U.S. Bankruptcy Code or encounters other financial difficulty, under federal or state laws governing fraudulent conveyance or preferential payments, a court in the relevant jurisdiction might void or cancel its guarantee. The court might do so if it found that, when the guarantor entered into its guarantee or, in some states, when payments become due thereunder, it received less than reasonably equivalent value or fair consideration for such guarantee and either was or was rendered insolvent, was left with inadequate capital to conduct its business, or believed or should have believed that it would incur debts beyond its ability to pay. The court might also void such guarantee, without regard to the above factors, if it found that the guarantor entered into its guarantee with actual or deemed intent to hinder, delay, or defraud its creditors.

A court would likely find that a guarantor did not receive reasonably equivalent value or fair consideration for its guarantee unless it benefited directly or indirectly from the issuance of the notes. If a court voided such guarantee, you would no longer have a claim against such guarantor. In addition, the court might direct you to repay any amounts already received from such guarantor. If the court were to void any guarantee, we cannot assure you that funds would be available to pay the notes from another guarantor or from any other source.

The indenture will state that the liability of each guarantor on its guarantee is limited to the maximum amount that the guarantor can incur without risk that the guarantee will be subject to avoidance as a fraudulent conveyance. This limitation may not protect the guarantees from a fraudulent conveyance attack or, if it does, we cannot assure you that the guarantees will be in amounts sufficient, if necessary, to pay obligations under the notes when due.

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The notes currently have no established trading or other public market and, if one develops, it may not be liquid.

The notes will constitute a new issue of securities with no established trading market. Although we have agreed to use reasonable efforts to list the notes on the official list of the Luxembourg Stock Exchange and have the notes admitted to trading on the EuroMTF or another European stock exchange, we cannot assure you that an active trading market will develop for the notes even if we are successful in getting the notes listed. We cannot assure you that any market for the notes will develop, or if one does develop, that it may not be liquid. If the notes are traded, they may trade at a discount from their initial offering price, depending on prevailing interest rates, the market for similar securities, our credit rating, our operating performance and financial condition and other factors. As a result, we cannot ensure you that you will be able to sell any of the notes at a particular time, at attractive prices, or at all.

In addition, the market for non-investment-grade debt securities has historically been subject to disruptions that have caused price volatility independent of the operating and financial performance of the issuers of these securities. It is possible that the market for the notes, or the exchange notes, if any are issued, will be subject to these kinds of disruptions. Accordingly, declines in the liquidity and market price of the notes and the exchange notes, if any are issued, may occur independent of our operating and financial performance. If any notes are issued, any liquid market for the notes or the exchange notes is not certain to develop.

The trading prices for the notes will be directly affected by our credit rating.

Credit rating agencies continually revise their ratings for companies that they follow, including us. Any ratings downgrade could adversely affect the trading price of the notes or the trading market for the notes to the extent a trading market for the notes develops. The condition of the financial and credit markets and prevailing interest rates have fluctuated in the past and are likely to fluctuate in the future.

Because our Parent is incorporated under the laws of Bermuda, there may be difficulty in serving process on and enforcing liabilities against our Parent.

Our Parent, which will guarantee payments under the notes, is incorporated under the laws of Bermuda. Some of the directors and officers and a substantial portion of the assets of Parent are located outside the United States. Accordingly, it may be difficult for investors in the notes to effect service of process within the United States upon these persons or to enforce against them, in courts outside the United States, judgments of courts of the United States predicated upon civil liabilities under the U.S. federal securities or other laws.

We have been advised by our Bermuda legal counsel, Appleby Hunter Bailhache, that there is doubt with respect to Bermuda law as to (a) whether a judgment of a U.S. court predicated solely upon the civil liability provisions of the U.S. federal securities or other laws would be enforceable in Bermuda against Parent and (b) whether an action could be brought in Bermuda against Parent in the first instance on the basis of liability predicated solely upon the provisions of the U.S. federal securities or other laws. In addition, other laws of these jurisdictions, such as those limiting a party’s enforcement rights on the grounds of public policy of that jurisdiction, and the fact that a treaty may not exist between the United States and the governments of these jurisdictions regarding the enforcement of civil liabilities may also restrict the ability to enforce Parent’s obligations under its guarantee.

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our historical consolidated ratio of earnings to fixed charges for the periods shown:

	Nine Months Ended March 31, 2007		Period from February 7, 2006 (Inception) to June 30, 2006
	(Unaudited)		(Unaudited)
Ratio of Earnings to Fixed Charges		1.56x		1.38x

USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement we entered into in connection with issuance of the old notes. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated in this prospectus, we will receive, in exchange, outstanding old notes in like principal amount. We will cancel all old notes surrendered in exchange for new notes in the exchange offer. As a result, the issuance of the new notes will not result in any increase or decrease in our indebtedness.

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THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

We sold $750.0 million in aggregate principal amount at maturity of the old notes, which was completed on June 8, 2007. The old notes were sold to investors in a private placement in the United States in reliance on Section 4(2) and/or Regulation D of the Securities Act or to the initial purchasers who in turn resold the outstanding notes to offshore investors pursuant to Regulation S of the Securities Act.

In connection with the offering of the old notes, we entered into a registration rights agreement with the purchasers of the old notes, pursuant to which we agreed to file and to use our reasonable best efforts to cause to be declared effective by the SEC a registration statement with respect to the exchange of the old notes for the new notes. We are making the exchange offer to fulfill our contractual obligations under the agreement. A copy of the registration rights agreement has been filed as an exhibit to the registration statement of which this prospectus is a part.

Pursuant to the exchange offer, we will issue the new notes in exchange for old notes. The terms of the new notes are identical in all material respects to those of the old notes, except that the new notes (1) have been registered under the Securities Act and therefore will not be subject to certain restrictions on transfer applicable to the old notes and (2) will not have registration rights or provide for any additional interest related to the obligation to register. Please read “Description of the New Notes” for more information on the terms of the respective notes and the differences between them.

We are not making the exchange offer to, and will not accept tenders for exchange from, holders of old notes in any jurisdiction in which an exchange offer or the acceptance thereof would not be in compliance with the securities or blue sky laws of such jurisdiction. Unless the context requires otherwise, the term “holder” with respect to the exchange offer means any person in whose name the old notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder, or any person whose old notes are held of record by The Depository Trust Company, referred to as DTC, who desires to deliver such old notes by book-entry transfer at DTC.

We make no recommendation to the holders of old notes as to whether to tender or refrain from tendering all or any portion of their old notes pursuant to the exchange offer. In addition, no one has been authorized to make any such recommendation. Holders of old notes must make their own decision whether to tender pursuant to the exchange offer and, if so, the aggregate amount of old notes to tender after reading this prospectus and the letter of transmittal and consulting with the advisers, if any, based on their own financial position and requirements.

In order to participate in the exchange offer, you must represent to us, among other things, that:

• you are acquiring the new notes in the exchange offer in the ordinary course of your business;

• you are not engaged in, and do not intend to engage in, a distribution of the new notes;

• you do not have and to your knowledge, no one receiving new notes from you has, any arrangement or understanding with any person to participate in the distribution of the new notes;

• you are not a broker-dealer tendering old notes acquired directly from us for your own account or if you are a broker-dealer, you will comply with the prospectus delivery requirements of the Securities Act in connection with any resale of the new notes; and

• you are not one of our “affiliates,” as defined in Rule 405 of the Securities Act.

Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of Distribution.”

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Terms of Exchange

Upon the terms and conditions described in this prospectus and in the accompanying letter of transmittal, which together constitute the exchange offer, we will accept for exchange old notes that are properly tendered at or before the expiration time and not withdrawn as permitted below. As of the date of this prospectus, $750.0 million aggregate principal amount of old notes are outstanding. This prospectus, together with the letter of transmittal, is first being sent on or about the date on the cover page of the prospectus to all holders of old notes known to us. Old notes tendered in the exchange offer must be in denominations of principal amount of $2,000 and any integral multiple of $1,000.

Our acceptance of the tender of old notes by a tendering holder will form a binding agreement between the tendering holder and us upon the terms and subject to the conditions provided in this prospectus and in the accompanying letter of transmittal.

The form and terms of the new notes being issued in the exchange offer are the same as the form and terms of the old notes except that:

• the new notes being issued in the exchange offer will have been registered under the Securities Act;

• the new notes being issued in the exchange offer will not bear the restrictive legends restricting their transfer under the Securities Act; and

• the new notes being issued in the exchange offer will not contain the registration rights contained in the old notes.

Expiration, Extension and Amendment

The expiration time of the exchange offer is 5:00 P.M., New York City time, on       , 2007. However, we may, in our sole discretion, extend the period of time for which the exchange offer is open and set a later expiration date for the offer. The term “expiration time” as used herein means the latest time and date to which we extend the exchange offer. If we decide to extend the exchange offer period, we will then delay acceptance of any old notes by giving oral or written notice of an extension to the holders of old notes as described below. During any extension period, all old notes previously tendered will remain subject to the exchange offer and may be accepted for exchange by us. Any old notes not accepted for exchange will be returned to the tendering holder after the expiration or termination of the exchange offer.

Our obligation to accept old notes for exchange in the exchange offer is subject to the conditions described below under “— Conditions to the Exchange Offer.” We may decide to waive any of the conditions in our sole reasonable discretion. Furthermore, we reserve the right to amend or terminate the exchange offer, and not to accept for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified below under the same heading. We will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable. If we materially change the terms of the exchange offer, we will resolicit tenders of the old notes, file a post-effective amendment to the prospectus and provide notice to you. If the change is made less than five business days before the expiration of the exchange offer, we will extend the offer so that the holders have at least five business days to tender or withdraw. We will notify you of any extension by means of a press release or other public announcement no later than 9:00 A.M., New York City time, on the first business day after the previously scheduled expiration time.

Procedures for Tendering

Valid Tender

Except as described below, a tendering holder must, prior to the expiration time, transmit to Wells Fargo Bank, National Association, the exchange agent, at the address listed below under the caption “— Exchange Agent”:

• a properly completed and duly executed letter of transmittal, including all other documents required by the letter of transmittal; or

• if old notes are tendered in accordance with the book-entry procedures listed below, an agent’s message transmitted through DTC’s Automated Tender Offer Program, referred to as ATOP.

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In addition, you must:

• deliver certificates, if any, for the old notes to the exchange agent at or before the expiration time; or

• deliver a timely confirmation of the book-entry transfer of the old notes into the exchange agent’s account at DTC, the book-entry transfer facility, along with the letter of transmittal or an agent’s message; or

• comply with the guaranteed delivery procedures described below.

The term “agent’s message” means a message, transmitted by DTC to, and received by, the exchange agent and forming a part of a book-entry confirmation, that states that DTC has received an express acknowledgment that the tendering holder agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against such holder.

If the letter of transmittal is signed by a person other than the registered holder of old notes, the letter of transmittal must be accompanied by a written instrument of transfer or exchange in satisfactory form duly executed by the registered holder with the signature guaranteed by an eligible institution. The old notes must be endorsed or accompanied by appropriate powers of attorney. In either case, the old notes must be signed exactly as the name of any registered holder appears on the old notes.

If the letter of transmittal or any old notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless waived by us, proper evidence satisfactory to us of their authority to so act must be submitted.

By tendering, each holder will represent to us that, among other things, the person is not our affiliate, the new notes are being acquired in the ordinary course of business of the person receiving the new notes, whether or not that person is the holder, and neither the holder nor the other person has any arrangement or understanding with any person to participate in the distribution of the new notes. Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of Distribution.”

The method of delivery of old notes, letters of transmittal and all other required documents is at your election and risk, and the delivery will be deemed made only upon actual receipt or confirmation by the exchange agent. If the delivery is by mail, we recommend that you use registered mail, properly insured, with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery. Holders tendering through DTC’s ATOP system should allow sufficient time for completion of the ATOP procedures during the normal business hours of DTC on such dates.

No old notes, agent’s messages, letters of transmittal or other required documents should be sent to us. Delivery of all old notes, agent’s messages, letters of transmittal and other documents must be made to the exchange agent. Holders may also request their respective brokers, dealers, commercial banks, trust companies or nominees to effect such tender for such holders.

If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and wish to tender, you should promptly instruct the registered holder to tender on your behalf. Any registered holder that is a participant in DTC’s ATOP system may make book-entry delivery of the old notes by causing DTC to transfer the old notes into the exchange agent’s account. The tender by a holder of old notes, including pursuant to the delivery of an agent’s message through DTC’s ATOP system, will constitute an agreement between such holder and us in accordance with the terms and subject to the conditions set forth herein and in the letter of transmittal.

All questions as to the validity, form, eligibility, time of receipt and withdrawal of the tendered old notes will be determined by us in our sole reasonable discretion or by the exchange agent, which determination will be final and binding. We reserve the absolute right to reject any and all old notes not validly tendered or any old notes which, if accepted, would, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any irregularities or conditions of tender as to particular old notes. Our interpretation of the

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terms and conditions of this exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify you of defects or irregularities with respect to tenders of old notes, none of us, the exchange agent, or any other person shall be under any duty to give notification of defects or irregularities with respect to tenders of old notes, nor shall any of them incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such irregularities have been cured or waived. Any old notes received by the exchange agent that are not validly tendered and as to which the defects or irregularities have not been cured or waived will be returned without cost to such holder by the exchange agent, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date of the exchange offer.

Although we have no present plan to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any old notes that are not tendered in the exchange offer, we reserve the right, in our sole discretion, to purchase or make offers for any old notes after the expiration date of the exchange offer, from time to time, through open market or privately negotiated transactions, one or more additional exchange or tender offers, or otherwise, as permitted by law, the indenture and our other debt agreements. Following consummation of this exchange offer, the terms of any such purchases or offers could differ materially from the terms of this exchange offer.

Signature Guarantees

Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed, unless the old notes surrendered for exchange are tendered:

• by a registered holder of the old notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal, or

• for the account of an “eligible institution.”

If signatures on a letter of transmittal or a notice of withdrawal are required to be guaranteed, the guarantees must be by an “eligible institution.” An “eligible institution” is an “eligible guarantor institution” meeting the requirements of the registrar for the notes within the meaning of Rule 17Ad-15 under the Exchange Act.

Book-Entry Transfer

The exchange agent will make a request to establish an account for the old notes at DTC for purposes of the exchange offer. Any financial institution that is a participant in DTC’s system may make book-entry delivery of old notes by causing DTC to transfer those old notes into the exchange agent’s account at DTC in accordance with DTC’s procedure for transfer. The participant should transmit its acceptance to DTC at or prior to the expiration time or comply with the guaranteed delivery procedures described below. DTC will verify this acceptance, execute a book-entry transfer of the tendered old notes into the exchange agent’s account at DTC and then send to the exchange agent confirmation of this book-entry transfer. The confirmation of this book-entry transfer will include an agent’s message confirming that DTC has received an express acknowledgment from this participant that this participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this participant.

Delivery of new notes issued in the exchange offer may be effected through book-entry transfer at DTC. However, the letter of transmittal or facsimile of it or an agent’s message, with any required signature guarantees and any other required documents, must:

• be transmitted to and received by the exchange agent at the address listed under “— Exchange Agent” at or prior to the expiration time; or

• comply with the guaranteed delivery procedures described below.

Delivery of documents to DTC in accordance with DTC’s procedures does not constitute delivery to the exchange agent.

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Guaranteed Delivery

If a registered holder of old notes desires to tender the old notes, and the old notes are not immediately available, or time will not permit the holder’s old notes or other required documents to reach the exchange agent before the expiration time, or the procedures for book-entry transfer described above cannot be completed on a timely basis, a tender may nonetheless be made if:

• the tender is made through an eligible institution;

• prior to the expiration time, the exchange agent receives by facsimile transmission, mail or hand delivery from such eligible institution a properly and validly completed and duly executed notice of guaranteed delivery, substantially in the form provided by us:

(1) stating the name and address of the holder of old notes and the amount of old notes tendered,

(2) stating that the tender is being made, and

(3) guaranteeing that within three New York Stock Exchange trading days after the expiration time, the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

• the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and all other documents required by the letter of transmittal, are received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery.

Determination of Validity

We will determine in our sole reasonable discretion all questions as to the validity, form and eligibility of old notes tendered for exchange. This discretion extends to the determination of all questions concerning the timing of receipts and acceptance of tenders. These determinations will be final and binding. We reserve the right to reject any particular old note not properly tendered or of which our acceptance might, in our judgment or our counsel’s judgment, be unlawful. We also reserve the right to waive any defects or irregularities or conditions of the exchange offer as to any particular old note either before or after the expiration time, including the right to waive the ineligibility of any tendering holder. Our interpretation of the terms and conditions of the exchange offer as to any particular old note either before or after the applicable expiration time, including the letter of transmittal and the instructions to the letter of transmittal, shall be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within a reasonable period of time.

Neither we, the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity in any tender of old notes. Moreover, neither we, the exchange agent nor any other person will incur any liability for failing to give notifications of any defect or irregularity.

Acceptance of Old Notes for Exchange; Issuance of New Notes

Upon the terms and subject to the conditions of the exchange offer, we will accept, promptly after the expiration time, all old notes properly tendered. We will issue the new notes promptly after acceptance of the old notes. For purposes of an exchange offer, we will be deemed to have accepted properly tendered old notes for exchange when, as and if we have given oral or written notice to the exchange agent, with prompt written confirmation of any oral notice.

For each old note accepted for exchange, the holder will receive a new note registered under the Securities Act having a principal amount equal to that of the surrendered old note. As a result, registered holders of new notes issued in the exchange offer on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid on the old notes or, if no interest has been paid on the old notes, from June 8, 2007. Old notes that we accept for exchange will cease to accrue interest from and after the date of completion of the

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exchange offer. Under the registration rights agreement, we may be required to make additional payments in the form of additional interest to the holders of the old notes under circumstances relating to the timing of the exchange offer.

In all cases, issuance of new notes for old notes will be made only after timely receipt by the exchange agent of:

• certificate for the old notes, or a timely book-entry confirmation of the old notes, into the exchange agent’s account at the book-entry transfer facility;

• a properly completed and duly executed letter of transmittal or an agent’s message;

• all other required documents.

Unaccepted or non-exchanged old notes will be returned without expense to the tendering holder of the old notes. In the case of old notes tendered by book-entry transfer in accordance with the book-entry procedures described above, the non-exchanged old notes will be credited to an account maintained with DTC as promptly as practicable after the expiration or termination of the exchange offer. For each old note accepted for exchange, the holder of the old note will receive a new note having a principal amount equal to that of the surrendered old note.

Interest Payments on the New Notes

The new notes will bear interest from the most recent date to which interest has been paid on the old notes for which they were exchanged. Accordingly, registered holders of new notes on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid. Old notes accepted for exchange will cease to accrue interest from and after the date of completion of the exchange offer and will be deemed to have waived their rights to receive the accrued interest on the old notes.

Withdrawal Rights

Tender of old notes may be properly withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.

For a withdrawal to be effective with respect to old notes, the exchange agent must receive a written notice of withdrawal before the expiration time delivered by hand, overnight by courier or by mail, at the address indicated under “— Exchange Agent” or, in the case of eligible institutions, at the facsimile number, or a properly transmitted “Request Message” through DTC’s ATOP system. Any notice of withdrawal must:

• specify the name of the person, referred to as the depositor, having tendered the old notes to be withdrawn;

• identify the old notes to be withdrawn, including certificate numbers and principal amount of the old notes;

• contain a statement that the holder is withdrawing its election to have the old notes exchanged;

• other than a notice transmitted through DTC’s ATOP system, be signed by the holder in the same manner as the original signature on the letter of transmittal by which the old notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer to have the trustee with respect to the old notes register the transfer of the old notes in the name of the person withdrawing the tender; and

• specify the name in which the old notes are registered, if different from that of the depositor.

If certificates for old notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of these certificates the withdrawing holder must also submit the serial numbers of the particular certificates to be withdrawn and signed notice of withdrawal with signatures guaranteed by an eligible institution, unless this holder is an eligible institution. If old notes have been tendered in accordance with the procedure for book-entry transfer described below, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn old notes.

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Any old notes properly withdrawn will be deemed not to have been validly tendered for exchange. New notes will not be issued in exchange unless the old notes so withdrawn are validly re-tendered.

Properly withdrawn old notes may be re-tendered by following the procedures described under “— Procedures for Tendering” above at any time at or before the expiration time.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal.

Conditions to the Exchange Offer

Notwithstanding any other provisions of the exchange offer, or any extension of the exchange offer, we will not be required to accept for exchange, or to exchange, any old notes for any new notes, and, as described below, may terminate an exchange offer, whether or not any old notes have been accepted for exchange, or may waive any conditions to or amend the exchange offer, if any of the following conditions has occurred or exists:

• there shall occur a change in the current interpretation by the staff of the SEC which permits the new notes issued pursuant to such exchange offer in exchange for old notes to be offered for resale, resold and otherwise transferred by the holders (other than broker-dealers and any holder which is an affiliate) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such new notes are acquired in the ordinary course of such holders’ business and such holders have no arrangement or understanding with any person to participate in the distribution of the new notes;

• any action or proceeding shall have been instituted or threatened in any court or by or before any governmental agency or body seeking to enjoin, make illegal or delay completion of the exchange offer or otherwise relating to the exchange offer;

• any law, statute, rule or regulation shall have been adopted or enacted which, in our judgment, would reasonably be expected to impair our ability to proceed with such exchange offer;

• a banking moratorium shall have been declared by United States federal or New York State authorities;

• trading on the New York Stock Exchange or generally in the United States over-the-counter market shall have been suspended, or a limitation on prices for securities imposed, by order of the SEC or any other governmental authority;

• an attack on the United States, an outbreak or escalation of hostilities or acts of terrorism involving the United States, or any declaration by the United States of a national emergency or war shall have occurred;

• a stop order shall have been issued by the SEC or any state securities authority suspending the effectiveness of the registration statement of which this prospectus is a part or proceedings shall have been initiated or, to our knowledge, threatened for that purpose or any governmental approval has not been obtained, which approval we shall, in our sole reasonable discretion, deem necessary for the consummation of such exchange offer; or

• any change, or any development involving a prospective change, in our business or financial affairs or any of our subsidiaries has occurred which is or may be adverse to us or we shall have become aware of facts that have or may have an adverse impact on the value of the old notes or the new notes, which in our sole judgment in any case makes it inadvisable to proceed with such exchange offer and/or with such acceptance for exchange or with such exchange.

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If any of the foregoing events or conditions has occurred or exists, we may, subject to applicable law, terminate the exchange offer, whether or not any old notes have been accepted for exchange, or may waive any such condition or otherwise amend the terms of such exchange offer in any respect. Please read “— Expiration, Extension and Amendment” above.

If any of the above events occur, we may:

• terminate the exchange offer and promptly return all tendered old notes to tendering holders;

• complete and/or extend the exchange offer and, subject to your withdrawal rights, retain all tendered old notes until the extended exchange offer expires;

• amend the terms of the exchange offer; or

• waive any unsatisfied condition and, subject to any requirement to extend the period of time during which the exchange offer is open, complete the exchange offer.

We may assert these conditions with respect to the exchange offer regardless of the circumstances giving rise to them. All conditions to the exchange offer, other than those dependent upon receipt of necessary government approvals, must be satisfied or waived by us before the expiration of the exchange offer. We may waive any condition in whole or in part at any time in our sole reasonable discretion. Our failure to exercise our rights under any of the above circumstances does not represent a waiver of these rights. Each right is an ongoing right that may be asserted at any time. Any determination by us concerning the conditions described above will be final and binding upon all parties.

If a waiver constitutes a material change to the exchange offer, we will promptly disclose the waiver by means of a prospectus supplement that we will distribute to the registered holders of the old notes, and we will extend the exchange offer for a period of five to ten business days, as required by applicable law, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the exchange offer would otherwise expire during the five to ten business day period.

Resales of New Notes

Based on interpretations by the staff of the SEC, as described in no-action letters issued to third parties that are not related to us, we believe that new notes issued in the exchange offer in exchange for old notes may be offered for resale, resold or otherwise transferred by holders of the new notes without compliance with the registration and prospectus delivery provisions of the Securities Act, if:

• the new notes are acquired in the ordinary course of the holder’s business;

• the holders have no arrangement or understanding with any person to participate in the distribution of the new notes;

• the holders are not “affiliates” of ours within the meaning of Rule 405 under the Securities Act; and

• the holders are not a broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act.

However, the SEC has not considered the exchange offer described in this prospectus in the context of a no-action letter. The staff of the SEC may not make a similar determination with respect to the exchange offer as in the other circumstances. Each holder who wishes to exchange old notes for new notes will be required to represent that it meets the above four requirements.

Any holder who is an affiliate of ours or who intends to participate in the exchange offer for the purpose of distributing new notes or any broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act:

• cannot rely on the applicable interpretations of the staff of the SEC mentioned above;

• will not be permitted or entitled to tender the old notes in the exchange offer; and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any secondary resale transaction.

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Each broker-dealer that receives new notes for its own account in exchange for old notes must acknowledge that the old notes were acquired by it as a result of market-making activities or other trading activities and agree that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. Please read “Plan of Distribution.” A broker-dealer may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resales of new notes received in exchange for old notes that the broker-dealer acquired as a result of market-making or other trading activities. Any holder that is a broker-dealer participating in the exchange offer must notify the exchange agent at the telephone number set forth in the enclosed letter of transmittal and must comply with the procedures for broker-dealers participating in the exchange offer. We have not entered into any arrangement or understanding with any person to distribute the new notes to be received in the exchange offer.

In addition, to comply with state securities laws, the new notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification, with which there has been compliance, is available. The offer and sale of the new notes to “qualified institutional buyers,” as defined under Rule 144A of the Securities Act, is generally exempt from registration or qualification under the state securities laws. We currently do not intend to register or qualify the sale of new notes in any state where an exemption from registration or qualification is required and not available.

Exchange Agent

Wells Fargo Bank, National Association has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal and any other required documents should be directed to the exchange agent at the address or facsimile number set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent addressed as follows:

Wells Fargo Bank, National Association

By Facsimile for Eligible Institutions: (214) 777-4086 Attention: Patrick T. Giordano	By Mail/Overnight Delivery/Hand: Wells Fargo Bank, NA Corporate Trust Services 1445 Ross Avenue – 2nd Floor Attention: Patrick T. Giordano	Confirm by Telephone: (214) 740-1573

Delivery of the letter of transmittal to an address other than as set forth above or transmission of such letter of transmittal via facsimile other than as set forth above does not constitute a valid delivery of the letter of transmittal.

Fees and Expenses

The expenses of soliciting tenders pursuant to this exchange offer will be paid by us. We have agreed to pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection with the exchange offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus and related documents to the beneficial owners of old notes, and in handling or tendering for their customers. We will not make any payment to brokers, dealers or others soliciting acceptances of the exchange offer.

Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes on the exchange. If, however, new notes are to be delivered to, or are to be issued in the name of, any person other than the registered holder of the old notes tendered, or if a transfer tax is imposed for any reason other than the exchange of old notes in connection with the exchange offer, then the amount of any such transfer taxes (whether imposed on the registered holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder.

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Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

Consequences of Failure of Exchange Outstanding Securities

Holders who desire to tender their old notes in exchange for new notes registered under the Securities Act should allow sufficient time to ensure timely delivery. Neither the exchange agent nor us is under any duty to give notification of defects or irregularities with respect to the tenders of old notes for exchange.

Old notes that are not tendered or are tendered but not accepted will, following the completion of the exchange offer, continue to be subject to the provisions in the indenture regarding the transfer and exchange of the old notes and the existing restrictions on transfer set forth in the legend on the old notes set forth in the indenture for the notes. Except in limited circumstances with respect to specific types of holders of old notes, we will have no further obligation to provide for the registration under the Securities Act of such old notes. In general, old notes, unless registered under the Securities Act, may not be offered or sold except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws.

We do not currently anticipate that we will take any action to register the old notes under the Securities Act or under any state securities laws. Upon completion of the exchange offer, holders of the old notes will not be entitled to any further registration rights under the registration rights agreement, except under limited circumstances.

Holders of the new notes issued in the exchange offer, any old notes which remain outstanding after completion of the exchange offer and the previously issued notes will vote together as a single class for purposes of determining whether holders of the requisite percentage of the class have taken certain actions or exercised certain rights under the indenture.

Accounting Treatment

We will record the new notes at the same carrying value as the old notes, as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. The expenses of the exchange offer will be amortized over the term of the new notes.

Other

Participation in the exchange offer is voluntary, and you should consider carefully whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

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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 otherprocessing 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.”

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SELECTED FINANCIAL INFORMATION OF ENERGY XXI GULF COAST, INC.

The following table sets forth our selected financial data as of March 31, 2007 and June 30, 2006 and for the nine months ended March 31, 2007 and for the period from February 7, 2006 (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 February 7, 2006 (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 and for the nine month period ended March 31, 2007 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, 2004 and 2003, 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.

	Energy XXI Gulf Coast, Inc. (Successor)					Marlin (Predecessor)
	Actual
	Nine Months Ended March 31, 2007 (unaudited)			Period from February 7, 2006 to June 30, 2006(1)		Three Months Ended March 31,		Year Ended December 31,
						2006		2005		2004		2003
	($ in Millions)
Statements of Operations Data:
Oil sales	$	121.9		$	29.1	$	26.5	$	74.1	$	65.1	$	21.3
Natural gas sales		100.7			18.0		19.9		90.0		36.9		4.4
Total revenues		222.6			47.1		46.4		164.1		102.0		25.7
Lease operating expense, production taxes and transportation		36.5			10.0		11.2		38.2		18.0		6.0
Depreciation, depletion and amortization		87.4			20.2		12.7		39.0		26.6		9.2
Accretion of asset retirement obligations		2.6			0.7		0.7		2.9		1.5		0.2
General and administrative expenses		26.7			3.5		1.5		6.0		4.6		1.7
Loss (gain) on derivative financial instruments		(3.1	)		0.1		—		—		—		—
Operating income	$	72.5		$	12.6	$	20.3	$	78.0	$	51.3	$	8.6
Net income	$	22.1		$	3.0	$	20.3	$	78.0	$	51.3	$	8.6
Capital expenditures	$	248.8		$	17.4	$	47.9	$	104.9	$	59.5	$	4.3

(1) Exploration and production activities commenced in April 2006 with the acquisition of Marlin and its Gulf of Mexico assets.

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	Energy XXI Gulf Coast, Inc. (Successor)				Marlin Predecessor
	March 31, 2007 (unaudited)		June 30, 2006		December 31, 2005		December 31, 2004		December 31, 2003
	($ in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	6,475	$	4,144	$	1,892	$	2,666	$	571
Property and equipment — net		925,906		447,852		303,722		271,322		86,620
Total assets		1,057,142		576,762		375,028		291,187		96,113
Long-term obligations (including current maturities of long-term debt)		541,901		209,228		—		—		—
Stockholder’s equity		388,504		272,952

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		2005		2004
	(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 a Houston-based 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. Our parent, Energy XXI (Bermuda) Limited (our “Parent”), completed a $300 million initial public offering of common stock and warrants on the Alternative Investment Market (“AIM”) of the London Stock Exchange in October 2005. Since our formation, 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 ourexploration 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 $978.5 million of indebtedness outstanding, consisting of $750 million of notes offered and sold, $218.5 million under our first lien revolving credit facility and $10 million in put financings. 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.

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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.

	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		—		—
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		—		—
		1,060,355		78,174		11,292		219,913		750,976
Other Long-Term Obligations:
Asset retirement obligations		70,281		1,325		2,993		3,572		62,391
Total Contractual Obligations and Commitments	$	1,130,636	$	79,499	$	14,285	$	223,485	$	813,367

First Lien Revolver

Our first lien revolver was amended and restated on June 8, 2007. This facility is guaranteed by our Parent and all of its 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 0.50% to 1.25%. However, if an additional equity contribution in an amount of at least $50 million is made by our Parent to us, 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 $277 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 as of June 30, 2007), our interest rate coverage ratio to be less than 3.0 to 1.0, or our current ratio (in each case as defined in our first lien revolving credit facility) to be less than 1.0 to 1.0, in each case, as of the end of each fiscal quarter. In addition, we are subject to various covenants including those limiting dividends and other payments, making certain investments, margin, consolidating, modifying certain agreements, transactions with affiliates, the incurrence of debt, changes in control, asset sales, liens on properties, sale leaseback transactions, entering into certain leases, the allowance of gas imbalances, take or pay or other prepayments, entering into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr., Steven A. Weyel and David West Griffin in their current executive positions, subject to certain exceptions in the event of death or disability to one of these individuals.

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

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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, we completed the offering of the old notes. The notes are guaranteed by our Parent and each of our 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. For additional information regarding the notes, see “Description of New Notes.”

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 June 30, 2007, our hedge financing totaled $8.4 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 February 7, 2006 (inception) to June 30, 2006. At June 30, 2006, we had a working capital surplus of $41.8 million. At March 31, 2007, we had a working capital surplus of $46.6 million.

Operating, Investing and Financing Activities

Operating Activities

Nine Month Period Ended March 31, 2007

For the nine month period ended March 31, 2007, we generated net income of $22.1 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 a large level of working capital, excluding cash balances, of $40.2 million. However, a significant portion of this working capital is transitory as it includes, an insurance receivable related to the Marlin acquisition, as described below, of $46.6 million in working capital at March 31, 2007, $15.5 million is the current portion of the fair value of our derivative instruments.

Period from February 7, 2006 (inception) to June 30, 2006

For the period from February 7, 2006 through June 30, 2006, we generated $3.0 million of net income, the bulk of which was attributable to operating activities after the completion of the Marlin 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 $20.2 million was the largest, enabled us to generate $26.2 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,

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excluding cash balances, totaling approximately $37.7 million comprised of $103.4 million of non-cash current assets and $65.7 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 $8.7 million for the period from February 7, 2006 (inception) to June 30, 2006. This increase was primarily a result of $3.0 million in net income and $20.2 million of depreciation, depletion and amortization and a $12.9 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

Net cash used in investing activities for the nine month period ended March 31, 2007 was $549.9 million which included $302.5 million for the acquisition of Castex and $248.8 million in capital expenditures related to the Marlin and Castex properties.

Period from February 7, 2006 (inception) to June 30, 2006

Net cash used in investing activities for the period from February 7, 2006 (inception) to June 30, 2006 included $448.4 million for the purchase of oil and gas properties which closed on April 4, 2006, $17.4 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 $10.0 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

Net cash provided by financing activities excluding intercompany activity for the nine month period ended March 31, 2007 was $411.1 million. This included $364.0 million in proceeds from borrowings under the first and second lien revolving credit facilities, contributions from Parent of $83.9 million and payments on the financed puts of $7.0 million. Payments on the first and second lien revolving credit facilities totaled $24.6 million and debt issuance costs totaled $4.7 million.

Period from February 7, 2006 (inception) to June 30, 2006

Net cash provided by financing activities for the period from February 7, 2006 (inception) to June 30, 2006 included $274.5 million in proceeds from the issuance of equity securities, $192.5 million in borrowings under our credit facilities and $11.7 million in advances from affiliates which was offset by $4.0 million in payments for debt issuance related costs.

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 February 7, 2006 (inception) to June 30, 2006. Note that significant oil and gas operations commenced with our acquisition of oil and gas properties on April 4, 2006. 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 Month Period Ended March 31, 2007								Period from February 7, 2006 (inception) 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

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	Nine Month Period Ended March 31, 2007								Period from February 7, 2006 (inception) to June 30, 2006(1)
	Gas		Oil		Dry		Total		Gas		Oil		Dry		Total
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 to February 7, 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

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 revenues were $222.6 million due to the acquisition of Marlin on April 4, 2006 and the acquisition of Castex on July 28, 2006.

Period from February 7, 2006 (inception) to June 30, 2006

For the period from February 7, 2006 (inception) to June 30, 2006, oil and gas revenues were $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 February 7, 2006 (inception) to June 30, 2006.

Operational Information

	Nine Months Ended March 31, 2007		Period from February 7, 2006 (inception) to June 30, 2006
Oil, gas and NGL sales, excluding $22,889 and $1,427 in a gains related to the impact of hedging program for the nine months ended March 31, 2007 and the period from February 7, 2006 (inception) to June 30, 2006, respectively (in thousands)	$	199,679	$	45,685
Gas sales — MMcf		12,911.82		2,458.90
Average sales price per Mcf	$	6.86	$	6.48
Oil sales — MBbls		1,863.31		446.40
Average sales price per Bbl	$	59.61	$	66.64
Production and operating costs (excluding depreciation, depletion and amortization) (in thousands)	$	36,547	$	9,986
Production and operating costs per equivalent Bbl	$	9.10	$	11.57
Depreciation, depletion and amortization (in thousands)	$	87,369	$	20,225
Net income (in thousands)	$	22,129	$	3,011
Working capital (in thousands)	$	46,640	$	41,839

Costs and Expenses

Nine month period ended March 31, 2007

Our lease operating expense, depreciation, depletion and amortization of oil and gas properties and general and administrative expense were $36.5 million, $87.4 million and $26.7 million, respectively, for the nine month period ended March 31, 2007.

Period from February 7, 2006 (inception) to June 30, 2006

Our lease operating expenses and depreciation, depletion and amortization of oil and gas properties of $10.0 million and $20.2 million, respectively, for the period from February 7, 2006 (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 $3.5 million for the period from February 7, 2006 (inception) to June 30, 2006, net of amounts capitalized directly related to oil and gas property acquisitions, exploration and development of $1.9 million, included employee salaries and related benefits, insurance and legal and other professional fees.

Other Income and Expense

Nine month period ended March 31, 2007

Our interest expense for the nine month period of $39.6 million included $32.4 million of interest related to the first lien revolving credit facility and second lien revolving credit facility, $6.0 million in debt issuance cost related to the first lien revolver and second lien facility, and $1.2 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.

Our interest income of $1.2 million during the nine month period ended March 31, 2007 related to the investment of cash funds.

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 35.1%.

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Period from February 7, 2006 (inception) to June 30, 2006

Interest expense of $7.9 million related to interest incurred on our first lien revolving credit facility, second lien revolving credit facility and note purchase agreement related to the Marlin acquisition in April 2006.

Our tax expense of $1.7 million for the period from February 7, 2006 (inception) to June 30, 2006 was a result of taxes on income at an effective rate of 36.4%.

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

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throughout the hedge period there is a high correlation of changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.

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

Price volatility within a measured month is the primary factor affecting the analysis of effectiveness of our oil and gas derivatives. Volatility can reduce the correlation between the hedge settlement price and the price received for physical deliveries. Secondary factors contributing to changes in pricing differentials include changes in the basis differential which is the difference 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 February 7, 2006 (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.

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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.

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.

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Quantitative and Qualitative Disclosures about Market Risk

Market-Sensitive Instruments and Risk Management

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

Commodity Price Risk

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

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

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

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

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

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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

Three Way Costless Collars	Quantity		Price		March 31, 2007 Fair Value
					(in thousands)
Crude Oil (MBbls)
April 1, 2007 to March 31, 2008		1,018	$	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.

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

We are a Houston-based 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. Our parent, Energy XXI (Bermuda) Limited (our “Parent”), completed a $300 million initial public offering of common stock and warrants on the Alternative Investment Market (“AIM”) of the London Stock Exchange in October 2005. Since our formation, 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.

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.

Our exploration and production activities commenced in April 2006 upon our Parent’s 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

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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.

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.

Our Strengths

High-quality resource base.  Based on each of the most recent reserve reports, the reserve base of our properties and the Pogo Properties consisted of 37.5 MMBoe and 20.9 MMBoe, respectively. We believe our assets are in high-quality, mature fields that have been producing oil and gas for many years at predictable rates. Our top two fields, South Timbalier 21 and Rabbit Island, have produced a cumulative 295 MMBbls and 1,674 Bcf, or 574 MMBoe as of March 31, 2007. These prolific fields have allowed us to identify a large inventory of development and exploration opportunities that have only moderate risk based on their location and the drilling history of the area. As of June 30, 2006, approximately 60% of our reserves were offshore and 40% were onshore. As of December 31, 2006, all of the reserves of the Pogo Properties were offshore.

Ability to exploit reserves.  We have average daily production for the first ten days of May 2007 in excess of 20,000 Boed. We have increased production on the South Timbalier 21 field from 6,900 Boed since we acquired the field on April 4, 2006 to 13,200 Boed for the month ended March 31, 2007, a 90% increase. The increase of production has come from 13 wells drilled, 10 well workovers, 8 rig recompletes and optimization of gas lift and well inflow performance. We anticipate that the Pogo Properties will present us with additional opportunities to enhance our offshore production.

Diversification of reserves and production.  Based on each of the most recent reserve reports, the reserve base of our properties and the Pogo Properties consisted of 37.5 MMBoe and 20.9 MMBoe, respectively, and our average production, after giving effect to the Pogo Acquisition, of 20,900 Boed would have been spread across 73 fields over 283,000 acres and a total of 153 drilling locations both onshore and offshore in the Gulf

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of Mexico. Additionally, our properties and the Pogo Properties have an average PV-10 per proved location of $3.7 million and $4.0 million, respectively. We believe our location and high producing well count significantly reduces single well exposure risk related to weather concerns.

Consistent, high margin operating results.  We believe our operating model leads to consistent, high margins on our oil and gas activities. Based on each of the most recent reserve reports, our properties and the Pogo Properties were approximately 40% and 70% oil and natural gas liquids, respectively, with 52% and 63% of production on the respective properties for the quarter ended March 31, 2007 coming from oil. On a Boe basis, oil has recently shown a higher price relative to natural gas. Additionally, our high level of hedged production has resulted in higher and more predictable realized prices on our volumes sold. From a realized price perspective, our location relative to the Henry Hub sales point, the settlement market for NYMEX, allows us to realize lower basis differentials. From a cost perspective, our location in southern Louisiana and the Gulf of Mexico shelf allows us to employ lower day-rate drilling and workover equipment compared to other areas in the Gulf of Mexico.

High operational control.  We operate 79% of our properties. We believe controlling operations in our fields enables increased efficiency in the management of our capital spending program and in the utilization of our technical resources. Additionally, operating a majority of our assets gives us flexibility to target prospective exploration leads and leverage our depth of experience in increasing field production through advanced recompletion and drilling techniques.

Significant development and exploitation drilling inventory.  As of March 31, 2007, we maintain an inventory of 153 development and exploration opportunities, after giving effect to the Pogo Acquisition, of over a total of 283,000 net acres. We expect the Pogo Acquisition will increase our net acreage position by approximately 48% and thus will substantially augment our drilling opportunities compared to our net acreage position as of March 31, 2007. We have a significant database of seismic data covering 2,400 square miles from our existing operations, which we plan to use to pursue our drilling opportunities aggressively in the near term to increase our current production and reserve base.

Emphasis on Safety.  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. We intend to apply our high safety standards to cause the Pogo Properties to meet all MMS requirements, consistent with our other properties.

Experienced management and technical team.  Our management team averages over 25 years of oil and gas operating experience in some of the largest offshore production areas of the globe, with specific expertise in the Gulf of Mexico. John Schiller, our Parent’s Chairman and Chief Executive Officer, has approximately 25 years of industry experience, including serving as vice president of exploration and production for Devon Energy and the executive vice president for Ocean Energy. Our technical team of 37 petrotechnical and drilling and production employees has extensive experience on the Gulf Coast and in the Gulf of Mexico.

Our Strategy

The key points of our business strategy can be summarized as follows:

Focused acquisition strategy.  We seek to acquire oil and gas assets such as the Pogo Properties that lend themselves to an intensive exploitation program to significantly increase production and ultimate recovery of reserves. As part of our strategy, we plan to leverage our management team’s extensive expertise with geographically-focused, shorter-lived, high cash flow generating reservoirs. Due to our management team’s background, we believe we are well-positioned to identify and exploit these undervalued acquisition opportunities. The combination of high near-term cash flow together with our ability to manage and acquire these shorter-lived assets at favorable valuations results in higher returns on capital.

Intensive exploitation of reserves.  Our exploitation strategy focuses on enhancing production and the ultimate recovery of our offshore assets. By utilizing advanced geophysical, drilling, completion and production techniques and controlling operations, we can optimize reserves and production from our offshore assets. The production from our largest field, South Timbalier 21, has realized a 90% increase in daily production levels since inception to the month ended March 31, 2007. Our exploitation of this field has involved the drilling of 13 new wells and 10 workovers of existing wells. Since we acquired South Timbalier 21, our technical expertise has enabled us to increase production to a 21-year high in this large legacy field. We have

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identified 19 proved drilling opportunities in South Timbalier 21, and we anticipate selectively employing our exploitation strategy to our other offshore assets. We believe the Pogo Properties represent a similar opportunity as we had with the Marlin acquisition, where we have successfully enhanced production since we bought these properties.

Utilize and enhance seismic database to expand onshore exploration opportunities.  We acquire, merge and reprocess onshore seismic data into an integrated database, which has enabled us to identify a number of additional drilling opportunities that we believe can generate significant future value. We have drilled 12 exploratory wells during fiscal year 2007, including one exploratory well and one development well on our Oaks Estates properties. Our recently announced successful test on May 1, 2007 of a combined rate of 17,100 Mcfpd on our Oaks Estates wells, in addition to other successfully drilled targets, reflects the successful implementation of this strategy. Following the Pogo Acquisition, we now have 283,000 net acres across which we plan to continue executing our exploration strategy.

Employ a comprehensive hedging program to manage commodity price risk.  We are focused on managing and mitigating risk across our business and believe we substantially reduce our overall risk profile by utilizing hedges to mitigate commodity price risk. We actively hedge our forecast proved developed producing production, including hedging the new properties we acquire. By maintaining a relatively high level of hedged production, our cash flow in the short to intermediate term correlates more to production levels than to changes in commodity prices. Additionally, we believe an active hedging program provides more revenue certainty, allowing an efficient allocation of our capital resources and minimize our operating costs.

Reserves

The following table sets forth certain information with respect to our proven reserves by reserve category as of June 30, 2006 as estimated by Netherland, Sewell & Associates, Inc. This table also includes proved reserve information for the Castex properties we acquired in July 2006 after our fiscal year end as if we acquired these properties on June 30, 2006. The Castex reserves were estimated by Miller and Lents, Ltd. Reserves were estimated in accordance with standards of the SEC. Oil and natural gas liquids prices used are based on a June 30, 2006, West Texas Intermediate posted price of $70.75 per barrel and are adjusted by field for quality, transportation fees, and regional market differentials. Gas prices used are based on June 30, 2006, Henry Hub spot market price of $6.09 per MMBtu and are adjusted by field for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.

Reserve Category(1)(2)	Net Oil/NGL MBbls		Net Gas Mmcf		Total Vol Mboe		% of/ Total Category
Marlin Properties
Proven Developed Producing		4,505		27,414		9,074		37 %
Proven Developed Non-Producing		4,417		14,832		6,889		28 %
Proven Undeveloped		4,898		22,405		8,632		35 %
Total Proven		13,820		64,651		24,595		100%
Castex Properties
Proven Developed Producing		235		27,644		4,842		38 %
Proven Developed Non-Producing		620		11,710		2,572		20 %
Proven Undeveloped		321		30,965		5,482		42 %
Total Proven		1,176		70,319		12,896		100%

The following table also sets forth certain information with respect to the reserves associated with the Pogo Properties as of December 31, 2006 as estimated by Ryder Scott Company, LP. All of the reserves of the Pogo Properties are offshore. Oil and natural gas liquids prices used with respect to the Pogo Properties are based on a December 31, 2006 West Texas Intermediate posted price of $61.06 per barrel and are adjusted by field for quality, transportation fees, and regional market differentials. Gas prices used are based on December 31, 2006, Henry Hub spot market price of $5.62 per MMBtu and are adjusted by field for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.

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Reserve Category(1)(2)	Net Oil/NGL MBbls		Net Gas Mmcf		Total Vol Mboe		% of/ Total Category
Pogo Properties
Proven Developed Producing		5,213		10,454		6,955		33 %
Proven Developed Non-Producing		6,230		13,807		8,531		41 %
Proven Undeveloped		3,255		13,203		5,456		26 %
Total Proven		14,698		37,464		20,942		100%

(1) Proved Developed Producing Reserves — Reserves subcategorized as producing are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after improved recovery project is in operation.

(2) Proved Developed Non-Producing Reserves — Reserves subcategorized as non-producing include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (a) completion intervals that are open at the time of the estimate but have not started producing, which include behind pipe reserves that are waiting for the lower interval to deplete until they are produced, (b) wells which were shut-in for market conditions or pipeline connections, or (c) wells not capable of production for mechanical reasons. Currently, we do not have any production shut-in for market conditions. However, if prices were to deteriorate to levels we considered unacceptable, we could shut-in selected production until prices increased to satisfactory levels. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.

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 February 7, 2006 (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 February 7, 2006 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 to February 7, 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.

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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 February 7, 2006 (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.

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

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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.

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

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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.

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.

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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 environmentin 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.

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

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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.

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, equal to $125 million for each named storm and in the aggregate, subject to a $7.5 million deductible for each named storm. 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.

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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 August 17, 2007, we had 89 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.

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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.

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. Two dry holes have currently been drilled under this Participation Agreement and the timing of additional drilling is currently being evaluated.

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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. The initial test well was commenced in August 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 was 3,163 Boed net. Reserves for Main Pass 61 as of December 31, 2006 totaled 8.5 MMBoe net.

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 was 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 Parent’s 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

We are an indirect wholly owned subsidiary of our Parent. The following table sets forth as of July 10, 2007 the number and percentage of the outstanding shares of our Parent’s 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)		15.90	%
Seneca Capital International Ltd. 590 Madison Avenue — 28 th Floor New York, New York 10022		12,020,605	(2)		13.05	%
Satellite Overseas Fund Ltd. c/o Morstan Nominees Limited 25 Cabot Square, Canary Wharf, London E14 4QW		9,764,587	(3)		10.77	%
Nathan Low 641 Lexington Ave., 25 th Floor New York, NY 10022		9,869,079	(4)		10.46	%
Nisswa Master Fund Ltd. 800 Nicollet Mall, Suite 2850 Minneapolis, MN 55402		5,978,500	(5)		6.61	%
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			5.92	%
Sunrise Equity Partners, L.P. 641 Lexington Ave., 25 th Floor New York, NY 10022		5,000,001	(7)		5.72	%
John D. Schiller, Jr.(8)(9)(10)(13)		9,514,201			10.91	%
Steven A. Weyel(9)(10)(13)		3,045,000			3.57	%
David West Griffin(9)(10)(11)(13)		1,467,701			1.73	%
Stewart Lawrence		20,100			*
William Colvin		71,382			*
Paul Davison		4,729			*
David M. Dunwoody		58,782			*
Hill A. Feinberg		255,101			*
Ben Marchive(13)		183,333			*

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Name and Address of Beneficial Owner	Number of Common Shares		Percent of Class
Steve Nelson(13)		115,833		*
All directors and officers as a group (10 persons as of August 17, 2007)		14,736,162		16.77	%

* Indicates less than 1%

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

(2) Includes 7,588,370 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 5,978,500 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 common stock underlying warrants of 2,725,001, 383,333 and 261,080 with respect to Mr. Schiller, Mr. Weyel and Mr. Griffin, respectively.

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

(12) 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.

(13) Includes 60,000, 50,000, 32,500, 50,000 and 42,500 shares of restricted stock for Messrs. Schiller, Weyel, Griffin, Marchive and Nelson, respectively which were granted effective July 1, 2007 by the Parent’s Board of Directors on July 17, 2007.

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DIRECTORS AND EXECUTIVE OFFICERS

Parent

The following table sets forth the names, ages, and positions of each of our Parent’s 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 Parent’s 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 Parent’s Class I directors are Hill A. Feinberg and David West Griffin, our Parent’s Class II directors are Steven A. Weyel, Paul Davison and David M. Dunwoody and our Parent’s 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 Parent’s Chairman and Chief Executive Officer and has been since its inception in July 2005. 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 Parent’s nominating committee.

Steven A. Weyel. Mr. Weyel is our Parent’s 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

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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.

David West Griffin. Mr. Griffin is our Parent’s Chief Financial Officer and has been since its 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 Parent’s 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 Parent’s 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 Parent’s 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 Parent’s 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

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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 Parent’s 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, Mr. Marchive managed all disciplines of engineering dealing with drilling, production operations, completions and reserve determination for the offshore division. In February 1999 he 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 Parent’s 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.

Hugh A. Menown. Mr. Menown is our Parent’s 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 Parent’s 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 of our Parent 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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Gulf Coast

Our board of directors is comprised of three directors: John D. Schiller, Jr., Steven A. Weyel and David West Griffin. Each of our directors holds office until the next annual general meeting for the election of directors and until his successor has been duly elected and qualified. Members of our board of directors receive no compensation for their board duties. Our executive officers are Ben Marchive (President), Rick D. Fox (Chief Financial Officer, Treasurer and Secretary), Steve Nelson (Vice President of Operations) and J. Granger Anderson (Vice President of Land).

The following is information on the business experience of each of our officers who are not also officers of our Parent.

J. Granger Anderson. Mr. Anderson is our Vice President of Land and he has over 25 years of experience as a Petroleum Landman. He was hired from Kerr-McGee Corporation in April 2006, where he held the position of Chief Landman, Gulf of Mexico. Prior to joining Kerr-McGee, he worked at Westport Resources Corporation and Burlington Resources, Inc. Mr. Anderson graduated from Texas A&M University with a Bachelor of Science in Agricultural Economics in 1977.

Rick D. Fox. Mr. Fox is our Chief Financial Officer, Treasurer and Secretary. He was hired from Peoples Energy Production Company where he was the Director of Accounting and Control. Mr. Fox has 32 years experience in the oil and gas industry, including 16 years with Burlington Resources in various management positions. Mr. Fox graduated from Baylor University in 1974 and is a Certified Public Accountant.

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We were originally formed and incorporated in July 2005 as an exempted company under the laws of Bermuda to serve as a vehicle for the acquisition of oil and gas reserves and related assets. In October 2005, we completed a $300 million initial public offering of common stock and warrants on the “Alternative Investment Market” (“AIM”) of the London Stock Exchange Our formation and our initial activities, including our initial public offering on the AIM and our initial acquisition of Marlin, were a direct result of the efforts of Messrs. Schiller, Weyel and Griffin, who provided the Company’s original business plan and start-up capital through The Exploitation Company, LLP, a limited liability partnership created by Messrs. Schiller, Weyel and Griffin for such purpose. Our executive compensation programs and policies, particularly with regard to the compensation and equity ownership of Messrs. Schiller, Weyel and Griffin, are directly impacted by such history.

Compensation Program and Philosophy

The purpose of our compensation program is to attract and retain employees by providing a competitive compensation package through a combination of base salary, cash bonuses, equity incentives and other perquisites and benefits. Our executive officer compensation philosophy is to provide our executives with appropriate and competitive individual pay opportunities which reward the attainment of superior corporate and individual performance objectives. Our programs are designed to attract, retain, motivate and reward qualified executive officers to achieve performance goals aligned with our business objectives and the interests of our shareholders. The ultimate goal of our program is to increase shareholder value by providing executive officers with appropriate incentives to achieve our business objectives.

Our history impacts the mix of incentives offered to our executive officers. Each of Messrs. Schiller, Weyel and Griffin possess substantial equity ownership in the company due to their involvement in our initial establishment and initial activities. Thus, through fiscal year 2007, our primary incentives for Messrs. Schiller, Weyel and Griffin are offered through our salary, cash bonus, profit sharing and benefits programs. Our other executive officers do not possess such ownership interests and, therefore, we provide them with equity ownership incentives as well as other compensation program items. Our equity incentives are currently provided under the 2006 Long-Term Incentive Plan that is maintained by Energy XXI Services, LLC (the “2006 Long-Term Incentive Plan”), which is our wholly owned subsidiary through which we and our other subsidiaries are provided employee services and the costs of which are properly allocated among such entities.

For fiscal year 2008, the Remuneration Committee has established principles for determining performance-dependent multipliers to be applied to targets for cash bonuses and other compensation. The Remuneration Committee approves target performance objectives, both for the company and for our respective executive officers, for annual cash bonuses and other compensation, whether provided in the form of equity or cash. We believe that Messrs. Schiller’s, Weyel’s and Griffin’s substantial equity ownership, along with our use of equity incentives as part of total compensation, encourages these officers and our other employees to focus on our long-term performance. We also incorporate flexibility into our compensation program and in the assessment process to respond to and adjust for the evolving business environment.

Oversight of the Compensation Program

The Remuneration Committee is responsible for overseeing all of our compensation programs. As part of that responsibility, the Remuneration Committee reviews our compensation and benefits policies; evaluates the performance of our chief executive officer; approves the compensation levels for our executive officers; and reviews along with our board of directors with respect to our employee benefit plans, equity-based compensation plans and other compensation arrangements. Our current compensation program was established and implemented by the Remuneration Committee. It should be noted that Mr. Schiller, our chief executive officer, and Messrs. Weyel and Griffin were involved in the establishment and implementation of our compensation program as part of their substantial involvement in our initial start-up activities. Each of Messrs. Schiller, Weyel and Griffin were also involved in the negotiation and establishment of their own compensation arrangements as set forth in their respective employment agreements further described below. Each director that is a member of the Remuneration Committee qualifies as an “independent” director under NASDAQ rules and all independent members of the board of directors make up the entire Remuneration Committee at this time.

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Role of Remuneration Committee and Executive Officers in Compensation Decisions

The Remuneration Committee makes compensation decisions after completing its annual review process for each executive officer. Recommendations with respect to merit increases in base salary, the amount of cash bonuses and profit sharing awards and other compensation awards for executive officers are made by our chief executive officer based upon his rating of the performance of each other executive officer, within the pre-established ranges set by the Remuneration Committee, and presented to and reviewed by the Remuneration Committee. The Remuneration Committee may exercise its discretion and modify any awards as recommended by the chief executive officer.

Recommendations to the Remuneration Committee and compensation decisions are based on each executive’s performance against stated goals, which include, but are not limited to, a number of specific factors such as:

• increasing crude oil and natural gas reserves;

• key financial measurements such as revenue growth, operating profit, cash flow from operating activities and debt reduction;

• strategic objectives such as consummating acquisitions and partnership opportunities and incorporating further assets into operations, including through drilling and establishing of further developed reserves;

• promoting operational efficiency and oil and gas recovery methods;

• achieving specific operational goals, including improved productivity, simplification and risk management;

• achieving excellence in organizational structure and among our employees;

• supporting our values by promoting a culture of integrity through compliance with law and our ethics policies; and

• promoting and maintaining operational safety guidelines and procedures throughout the organization.

Elements of Compensation

Our annual executive compensation program primarily consists of:

• base salary;

• cash bonus;

• grants of equity incentive compensation;

• perquisites and other benefits and compensation arrangements; and

• profit sharing.

Other than for certain perquisites and benefits which are provided to all of our executive officers, individual performance has a significant impact on determining each compensation component. Each individual executive officer’s annual performance is measured based on a thorough review of their contributions to our business results both for the year and the long-term impact of the individual’s behavior and decisions.

We have employment agreements with each of Messrs. Schiller, Weyel and Griffin. These arrangements, which were entered into on April 4, 2006 in connection with our initial acquisition of the Marlin properties, as well as other key elements of and factors considered in determining the executive annual compensation program, are discussed below.

Base Salary

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, which amounts were the result of contract negotiations between the officers upon the formation of the company, but the foregoing amounts are now subject to annual review and adjustment by the Remuneration Committee. In July 2007, the Remuneration Committee modified the base

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salaries to be $525,000, $435,000, $285,000, $247,500 and $220,000 for Mr. Schiller, Mr. Weyel, Mr. Griffin, Mr. Marchive and Mr. Nelson, respectively. The Remuneration Committee reviews the performance of each of the five top executive officers and determines an appropriate salary level, cash bonuses and equity incentives based primarily on individual performance and industry competitive factors. These competitive factors may include the base salary of executives of comparable oil and natural gas exploration companies and other executives within the oil and gas industry in general. Included among those companies reviewed were Energy Partners, Ltd., Bois d’Arc Energy, Inc., Mariner Energy, Inc., W&T Offshore, Inc., Stone Energy Corp., and Callon Petroleum Company.

The named executive officers’ base salaries for the fiscal year ended June 30, 2007 are reported in the Summary Compensation Table under the “Salary” column.

Cash Bonuses

Annual cash bonuses are a core component of our compensation program. The Remuneration Committee considers the cash bonuses to reward achievement of corporate objectives and to align the interests of our executive officers with our shareholders by placing a significant portion of their compensation at risk.

Under the terms of their employment agreements, Messrs. Schiller, Weyel and Griffin have a target bonus expressed as a percentage of base salary (100% for Mr. Schiller, 75% for Mr. Weyel and 55% for Mr. Griffin) which the Remuneration Committee can use a multiple of, at their sole discretion, to determine the individual bonus amounts. For the fiscal year ended June 30, 2007, the Remuneration Committee determined that the Company should pay Messrs. Schiller, Weyel and Griffin cash bonuses of $950,000, $592,500 and $286,000, respectively, which correspond to the following percentages of their respective base salaries 200%, 150% and 110%.

Our other executive officers and other employees are also eligible to receive an annual cash bonus pursuant to operational and financial targets approved by the Remuneration Committee. For our fiscal year ending June 30, 2007, the cash bonuses provided to Messrs. Marchive and Nelson were in the amount of $275,000 and $190,000 respectively, which represents 122% and 95% of their respective base salaries.

The Remuneration Committee determined to grant cash bonuses for the fiscal year ended June 30, 2007 for each of Messrs. Schiller, Weyel, Griffin, Marchive and Nelson due to our growth during this year from both an operations and acquisitions perspective. The Remuneration Committee also considered the efforts of the named executive officers in establishing positive financial results and cash flows.

The named executive officers’ cash bonuses for the fiscal year ended June 30, 2007 are reported in the Summary Compensation Table under the “Bonus” column.

The Remuneration Committee also approved in July 2007 the bonus pool for the balance of the employees for fiscal year ended June 30, 2007.

Profit Sharing Arrangements

An additional component of our annual compensation program is our profit sharing program, which annually pays up to an amount equal up to 10% of an applicable employee’s base salary and cash bonus to a personal retirement account (much like a traditional 401(k) plan), that is maintained for such employee. The Remuneration Committee has the discretion to ultimately make the determination about the percentage of the respective named executive officer’s compensation that will be paid by us in any annual period. Much like the determinations with respect to cash bonuses, the Remuneration Committee reviews individual performance and competitive factors in making such determination. Such contributions are, to the extent they exceed certain levels, made to an unqualified deferred compensation program.

For the fiscal year ended June 30, 2007, the profit sharing amounts paid are reported in the Summary Compensation Table under the “All Other Compensation” column and the specific amounts are specifically set forth in the footnote to such column.

Equity Incentives

In connection with the formation of the company in July 2005, Messrs. Schiller, Weyel and Griffin purchased Common Shares of the company. As part of the offering of our Common Shares on AIM in

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October 2005, each of Messrs. Schiller, Weyel and Griffin signed agreements restricting the sale of their shares as purchased in July 2005 until October 20, 2008. In addition, as part of the offering of the company’s Common Shares on AIM each of Messrs. Schiller, Weyel and Griffin and partnerships controlled by these individuals purchased additional Common Shares as well as certain warrants purchased immediately after the listing on the open market.

The table below shows the beneficial ownership of each of Messrs. Schiller, Weyel and Griffin of Common Shares and the timing of the removal of the restriction on the sale or other transfer of such Common Shares.

Name	Common Shares/ Unrestricted			Common Shares/ Subject to Lock-Up(1)
John D. Schiller, Jr.		187,500	(2)		6,541,700	(3)
Steven A. Weyel		61,667	(2)		2,550,000
David West Griffin		86,621	(2)(4)		1,087,500

(1) Common Shares subject to lock-up restricting sale or transfer until October 20, 2008.

(2) Includes 87,500 Common Shares with respect to Mr. Schiller, 11,667 Common Shares with respect to Mr. Weyel, and 5,833 Common 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 and owners of 116,667 Common Shares.

(3) Includes 150,000 Common Shares owned by Mr. Schiller’s family members and 500,000 held in trust for the for the benefit of his family.

(4) Includes 200 Common Shares owned by Mr. Griffin’s family members.

The following table shows the beneficial ownership of each of Messrs. Schiller, Weyel and Griffin of warrants to purchase Common Shares, exercisable at $5.00 per Common Share.

Name	Number of Warrants Held(1)
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, LLP, a limited liability partnership and owner of 2,833,334 warrants.

Prior to fiscal year 2008, the Remuneration Committee did not feel that additional equity incentives were necessary due to the initial founding equity interests in the company owned by Messrs. Schiller, Weyel and Griffin. In order for these individuals to be rewarded for the achievement of corporate goals and objectives and to align their interests with our shareholders in fiscal year 2008, the Remuneration Committee has authorized the issuance of 60,000 shares of restricted stock and 60,000 restricted stock units for Mr. Schiller, 50,000 shares of restricted stock and 50,000 restricted stock units for Mr. Weyel, and 32,500 shares of restricted stock and 32,500 restricted stock units for Mr. Griffin, with vesting to occur on the first, second and third anniversaries of the award date. The primary difference between the restricted share and restricted stock unit awards is that we are entitled to settle our obligation under the restricted stock unit awards by the payment of cash in addition to settling such award through the delivery of common shares, while the delivery obligation on the restricted shares is to deliver the respective common shares.

As part of the initial hiring of Messrs. Marchive and Nelson, we agreed to provide incentive compensation to them in the form of restricted shares in the amount of 62,500 and 55,000 common shares, respectively, and restricted stock unit awards in the amount of 62,500 and 55,000 common shares, respectively. Both the restricted shares and the restricted stock unit awards, which were granted to Messrs. Marchive and Nelson on

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the effective hiring dates of April 10, 2006 for Mr. Marchive and April 17, 2006 for Mr. Nelson provide for ratable vesting on the anniversaries of such hiring dates over a three-year period. We had determined the total amount of share awards for each of Messrs. Marchive and Nelson as of their hiring — 125,000 shares for Mr. Marchive and 110,000 for Mr. Nelson — but did not ultimately split such awards into restricted shares and restricted stock unit awards until October 2006. The compensation expense for such awards was accrued in our fiscal year ended June 30, 2006.

Although none of the named executive officers received any further equity incentives under the 2006 Long-Term Plan during the fiscal year ended June 30, 2007, one-third of each of Messrs. Marchive’s and Nelson’s prior grants vested during the year. Thus, the restrictions on 20,833 and 18,333, respectively, of the number of restricted shares received by Messrs. Marchive and Nelson were lifted, and each of such named executive officers also received cash payment, at a value of $4.93 and $4.85 per share, respectively, on a same amount of their restricted stock unit awards.

Because we did not provide any further equity awards to the named executive officers for the fiscal year ended June 30, 2007, there was no compensation cost related to any such awards recognized by us for such year in accordance with “Statement of Financial Accounting Standards No. 123 (revised 2004) — Share Based Payment” (FAS 123R). Our prior grants to Messrs. Marchive and Nelson, as well as the payouts for vested awards during the fiscal year ended June 30, 2007, are reflected in the Outstanding Equity Awards at Fiscal Year End and Stock Vested tables, respectively.

The Remuneration Committee has awarded, in respect of our fiscal year 2008, 50,000 restricted common shares and 50,000 restricted stock units, and 42,500 restricted common shares and 42,500 restricted stock units respectively for Messrs. Marchive and Nelson.

In addition to the foregoing noted grants under the 2006 Long-Term Incentive Plan, the Remuneration Committee has agreed to provide restricted stock units to all of our other employees for Fiscal Year 2008.

The 2006 Long-Term Incentive Plan also provides the company the authority to offer options, stock appreciation rights, restricted stock and other stock or performance-based awards. As of the end of the fiscal year ended June 30, 2007, the Remuneration Committee offered restricted stock and restricted stock unit awards to our named executive officers and employees under the plan. In the future, the Remuneration Committee may decide to offer incentive compensation in the other forms as permitted by the 2006 Long-Term Incentive Plan. In deciding to do so, as well as any further awards of restricted stock or restricted stock units, the Remuneration Committee seeks to provide “pay for performance” by linking individual awards to both the company’s and the recipient’s individual performance. The Remuneration Committee believes that such performance considerations would include both financial and non financial objectives, including achieving certain financial targets in relation to internal budgets and developing internal infrastructure. The financial criteria include, among other things, increasing revenues, controlling direct and overhead expenses and increasing cash flow from operations. Non financial criteria include obtaining safety goals, enhancing our technical capabilities, increasing reserves and developing operations. The Remuneration Committee will also consider individual and overall corporate performance during any year in which incentives are considered to be granted, the amount of cash bonus as a percentage of an individual’s base salary, benchmarking data regarding peer group total cash compensation and total compensation, the recommendations of our chief executive officer, and other factors. The Remuneration Committee has stated to management that it believes that incentive awards are critical in motivating and rewarding the creation of long-term shareholder value.

Perquisites and Other Benefits

While not the primary focus of our compensation plans, the Remuneration Committee believes that the perquisites and other benefits that the company provides its executive officers constitute a material element of our compensation plans. Many of our benefits plans, such as our program to match contributions to its 401(k) plan, are standard in the market place for qualified executive officers and, thus, the Remuneration Committee believes such offerings are necessary to hire and retain qualified personnel. Likewise, we believe that additional perquisites such as our profit sharing contributions, additional life insurance coverage and use of Company-leased automobiles are customary offerings for executive officers for organizations doing business in the oil and gas industry and we offer these perquisites to remain competitive for qualified executive officer

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personnel. Finally, Messrs. Schiller, Weyel and Griffin have specific rights, under their respective employment agreements, to have the company pay for club membership fees and dues and the company has fulfilled these obligations.

Material Tax and Accounting Considerations

In designing its compensation programs, we take into consideration the tax and accounting effect that each element will or may have on us, the executive officers and other employees as a group. We aim to keep the expense related to our compensation programs as a whole within certain affordability levels. The number of common shares available under the 2006 Long-Term Incentive Plan and/or subject to equity awards may also be adjusted by the Remuneration Committee to prevent dilution or enlargement of rights in the event of various changes in our capitalization.

We have adopted the provisions of FAS 123R. All share-based payments to employees, including grants of restricted shares and restricted share units under the 2006 Long-Term Incentive Plan, are measured at fair value on the date of grant and recognized in the statement of operations as compensation expense over their vesting periods.

Section 162(m) of the United States Internal Revenue Code of 1986, as amended, generally disallows a tax deduction to public companies for certain compensation in excess of $1 million paid to our chief executive officer and our four other most highly compensated executive officers. As a new public company, we are eligible for special transition relief. We expect that future payments to each of our executive officers will generally comply with the rules of Section 162(m) through the fiscal year ended June 30, 2007. However, maintaining tax deductibility will not be the sole consideration taken into account by the Remuneration Committee in determining what compensation arrangements are in our and our shareholders’ best interests.

EXECUTIVE COMPENSATION TABLES

Summary Compensation Table

The following table presents compensation information for our fiscal year ended June 30, 2007 paid to or accrued for our chief executive officer, chief financial officer and each of our three other most highly compensated executive officers. We refer to these executive officers as our named executive officers.

Name and Principal Position	Year(1)		Salary(2)		Bonus		Stock Awards(3)(4)		All Other Compensation(4)(5)		Total
John D. Schiller, Jr. Chairman of the Board and Chief Executive Officer		2007	$	475,000	$	950,000			$	274,236	$	1,699,236
Steven A. Weyel President, Chief Operating Officer and Director		2007		395,000		592,500				185,992		1,173,492
David West Griffin Chief Financial Officer and Director		2007		260,000		286,000				105,018		651,018
Ben Marchive Senior Vice President, Operations		2007		225,000		275,000	$	205,414		96,892		802,306
Steve Nelson Vice President of Drilling and Production		2007		200,000		190,000		177,830		78,339		646,169

(1) References to “2007” in this column are to our fiscal year ended June 30, 2007.

(2) Includes amounts deferred in our Nonqualified Deferred Compensation Plan. In July 2007, the Remuneration Committee modified the base salaries to be $525,000, $435,000, $285,000, $247,500 and $220,000 for Mr. Schiller, Mr. Weyel, Mr. Griffin, Mr. Marchive and Mr. Nelson, respectively.

(3) Included in this column are grants of 62,500 restricted shares and 62,500 restricted stock unit awards

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granted to Mr. Marchive with respect to his hiring date of April 10, 2006 and 55,000 restricted shares and 55,000 restricted stock unit awards granted to Mr. Nelson with respect to his hiring date of April 17, 2006. The amounts in this column reflect the compensation cost related to such awards we recognized for the fiscal year ended June 30, 2007, in accordance with FAS 123R. For a discussion of the assumptions employed in determining the compensation cost reported above, please see the description under “Executive Compensation — Compensation Discussion and Analysis — Elements of Compensation — Material Tax and Accounting Considerations”. For fiscal year 2008, the Remuneration Committee has authorized the issuance of 60,000 shares of restricted stock and 60,000 restricted stock units for Mr. Schiller, 50,000 shares of restricted stock and 50,000 restricted stock units for Mr. Weyel, and 32,500 shares of restricted stock and 32,500 restricted stock units for Mr. Griffin, with vesting to occur on the first, second and third anniversaries of the award date. The Remuneration Committee also awarded, in respect of our fiscal year 2008, 50,000 restricted common shares and 50,000 restricted stock units, and 42,500 restricted common shares and 42,500 restricted stock units respectively for Messrs. Marchive and Nelson.

(4) Incentive awards paid in cash are reported under the “Bonus” column above or, if they relate to payments under our profit sharing arrangements, are reported under the “All Other Compensation” column and noted in specific amounts below.

(5) All Other Compensation amounts in the Summary Compensation Table consist of the following items:

Name	Life Insurance(a)		Automobile Leases(b)		Clubs(c)		Deferred Comp. Plan		Profit Sharing		401(k) Company Match		Total
John D. Schiller, Jr.	$	2,689	$	19,742	$	23,805	$	70,000	$	142,500	$	15,500	$	274,236
Steven A. Weyel		4,988		20,926		2,078		38,750		98,750		20,500		185,992
David West Griffin		2,927		14,731				17,260		54,600		15,500		105,018
Ben Marchive				16,892						50,000		20,500		87,392
Steve Nelson				15,939						39,000		15,500		70,439

(a) Represents values of life insurance premiums for coverage from the effective date of the insurance policies: with respect to Mr. Schiller, the annual premium is $16,135 with an effective date of April 27, 2007, with respect to Mr. Weyel, the annual premium is $11,970 with an effective date of January 22, 2007, and with respect to Mr. Griffin, the annual premium is $7,025 with an effective date of January 20, 2007.

(b) Represents the amount paid for company-leased automobiles provided for use by the respective named executive officer.

(c) Includes dues paid.

Narrative Disclosure to Accompany Summary Compensation Table

The compensation and awards disclosed in the foregoing Summary Compensation Table and Grant of Plan-Based Awards have been provided by us under the terms of our employment agreements with Messrs. Schiller, Weyel and Griffin, under our 2006 Long-Term Incentive Plan and compensation programs.

We entered into employment agreements with each of Messrs. Schiller, Weyel and Griffin on April 4, 2006. 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. Additionally, subject to the satisfaction of performance criteria established by the Remuneration Committee and approved by the board of directors, each of Messrs. Schiller, Weyel and Griffin have the opportunity to receive an annual target incentive bonus equal to a multiple of 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 employment agreements, each of Messrs. Schiller, Weyel and Griffin are also 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 our other benefits, plans or programs that may be available to our other executive employees from time to time.

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Each of Messrs. Schiller’s, Weyel’s and Griffin’s 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 so as to maintain a minimum one-year term unless either the applicable executive officer or we give written notice within 90 days prior to the end of the term that such party desires not to renew the applicable employment agreement. At any time, either party may terminate the executive officer’s employment under the applicable employment agreement for any reason. If any of Messrs. Schiller, Weyel or Griffin is subject to an “involuntary termination”, which means any termination other than one resulting from death, disability or resignation by the applicable executive officer (unless the executive officer is resigning within 60 days after a material change in the applicable executive officer’s duties, remuneration or terms) or resulting from our termination of the applicable executive officer for cause, such executive officer is entitled to the payments and compensation as described below under “Potential Payments Upon Termination or Change in Control,” which is a minimum of one year’s base salary and the average of the prior two years’ bonus amounts.

Our compensation of Messrs. Marchive and Nelson is pursuant only to our general compensation policies and programs.

Our 2006 Long-Term Incentive Plan enables our Remuneration Committee to grant awards of restricted shares, restricted share units, share appreciation rights, performance awards and options to any of our employees. We have reserved a total of 1,250,000 common shares for issuance under the 2006 Long-Term Incentive Plan although the Remuneration Committee has recommended, and the board has approved the expansion of this facility to 5,000,000 common shares. It is the intent of the board of directors to submit this amendment to the shareholders for approval at the next annual shareholders meeting. In connection with each of Messrs. Marchive’s and Nelson’s hiring in April 2006, the Remuneration Committee agreed to award 62,500 restricted shares and 62,500 restricted stock unit awards to Mr. Marchive and 55,000 restricted shares and 55,000 restricted stock unit awards to Mr. Nelson, in each case with ratable vesting over a three-year period on the anniversaries of their respective hiring dates (April 10, 2006 for Mr. Marchive and April 17, 2006 for Mr. Nelson). Messrs. Marchive’s and Nelson’s restricted stock unit awards cease to vest upon termination of employment, unless such termination is related to such executive officer’s death or disability.

All of the remaining compensation for the named executive officers is pursuant to perquisites and benefits plans maintained by us. For the fiscal year ended June 30, 2007, the Remuneration Committee determined that we should provide payments to the respective retirement accounts for the named executive officers in an amount equal to 10% of their respective amount of base salary and cash bonus for such year.

We did not make any grant of plan-based awards to the named executive officers during the fiscal year ended June 30, 2007. However, subsequent to such fiscal year, we did grant plan-based awards to these executive officers as previously described.

Outstanding Equity Awards at Fiscal Year End

The following table provides information concerning restricted common shares awards that have not vested for each of the named executive officers, outstanding as of June 30, 2007. As described in greater detail under “Executive Compensation — Compensation Discussion and Analysis — Elements of Compensation — Equity Incentives,” Messrs. Schiller, Weyel and Griffin and partnerships controlled by them possess warrants and unit purchase options to purchase our common shares, but these securities were purchased by each of Messrs. Schiller, Weyel and Griffin and such partnerships in the market at the time of and in connection with our initial public offering of our common shares on AIM on October 20, 2005. The amounts reflected as Market Value are based on the closing price of our common shares of $6.45 on June 29, 2007 (the last trading day of our fiscal year ended June 30, 2007).

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	Equity Incentive Plan Awards
Name	Number of Shares or Units of Stock That Have Not Vested(1)		Market or Payout Value of Shares or Units of Stock That Have Not Vested
Ben Marchive		83,334	$	537,504
Steve Nelson		73,334		473,004

(1) The amounts shown are under the grants of 62,500 restricted shares and 62,500 restricted stock unit awards granted to Mr. Marchive with respect to his hiring date of April 10, 2006 and 55,000 restricted shares and 55,000 restricted stock unit awards granted to Mr. Nelson with respect to his hiring date of April 17, 2006. The amounts of such grants that have vested are reflected below under the Stock Vested in 2007 table.

STOCK VESTED IN 2007

The following table shows on an aggregate basis for each named executive officer the vesting of restricted common share awards during the Company’s fiscal year ended June 30, 2007. As previously noted, we have never awarded any employees options to purchase our common shares. The amounts reflected as Value Realized on Vesting are based on the closing price of our common shares $4.93 and $4.85 on April 10, 2007 and April 17, 2007, the respective vesting dates for Messrs. Marchive and Nelson.

	Stock Awards
Name	Number of Shares Acquired on Vesting		Value Realized on Vesting
Ben Marchive		41,666	$	205,414
Steve Nelson		36,666		177,830

Pension Benefits

At present, we do not maintain or provide any benefits under any pension plan.

Potential Payments and Benefits Upon a Termination of Employment or a Change of Control

The following table reflects potential payments and benefits to the named executive officers under their employment agreements regarding a termination of such executive officers’ employment (including a resignation by such executive officers in respect of any change in the applicable officer’s responsibilities or for good reason). The following table does not reflect potential payments to the named executive officers in the event an executive officer voluntarily resigns his employment (without a “change in duties” or “good reason” as described in the text below) or such employment is terminated by us for “cause” (as described in the text below) or in connection with the death or “disability” (as described in the text below) of the executive officer.

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The amounts shown in the table assume that the applicable termination was effective on June 30, 2007. We have not included amounts payable in respect of accrued but unpaid salary under our ordinary payroll nor do we include amounts available under benefits practices and programs that do not discriminate in scope, terms or operation in favor of our executive officers and that are generally available to our salaried employees.

Company Obligations Upon Termination

Name	Severance(1)		Equity Awards(2)	Continued Benefits(3)		Tax Gross-Up(4)	Total
John D. Schiller, Jr.	$	1,741,667		$	101,775		$	1,843,442
Steven A. Weyel		1,217,917			58,545			1,276,462
David West Griffin		607,000			72,435			679,435

(1) In the case of Messrs. Schiller, Weyel and Griffin, the “Severance” amount reflects payment of an amount equal to: (x) the sum of (i) such executive officer’s base salary at the annual rate in effect at the time of termination and (ii) the average of the annual bonuses earned by such executive officer with respect each of our two prior fiscal years ended June 30, 2007 and 2006, multiplied by (y) 1.3 (which is equivalent to a fraction, the numerator of which is the number of full and partial months in the period beginning on the deemed date of such termination and ending on October 20, 2008, which is the last day of the remaining term of such executive officer’s employment under such applicable executive officer’s employment agreement). Under the employment agreements the multiplier explained in (y) may not be less than 1. As explained further below, the payments of the respective amounts of “Severance” are payable as a lump sum amount. In July 2007, the Remuneration Committee modified the base salaries to be $525,000, $435,000 and $285,000 for Mr. Schiller, Mr. Weyel and Mr. Griffin, which would increase the severance payments outlined in the above table. Also, in July 2007, the Company agreed to pay Mr. Marchive and Mr. Nelson severance payments of one year’s base salary upon termination.

(2) Under each of the employment agreements with Messrs. Schiller, Weyel and Griffin all options to purchase Common Shares become exercisable in full and all restricted Common Shares and restricted share units vest and become non forfeitable in the event of an “involuntary termination” during a change of control period. However, none of Messrs. Schiller, Weyel and Griffin possess options or restricted share units at this time. For fiscal year 2008, the Remuneration Committee has authorized the issuance of 60,000 shares of restricted stock and 60,000 restricted stock units for Mr. Schiller, 50,000 shares of restricted stock and 50,000 restricted stock units for Mr. Weyel, and 32,500 shares of restricted stock and 32,500 restricted stock units for Mr. Griffin, with vesting to occur on the first, second and third anniversaries of the award date.

(3) The amounts shown reflect the present value calculation of our obligations to continue to provide the applicable named executive officer and his spouse and dependents with continued coverage, or equivalent benefits, under our medical, dental and life insurance benefit plans on the same basis (and no greater cost to the applicable named executive officer) as provided at the time immediately prior to the applicable termination. Under the employment agreements with each of Messrs. Schiller, Weyel and Griffin, our obligation to provide such benefits is for a three-year period beginning on the date of the applicable termination, provided that the obligation terminates if and to the extent such executive officer becomes eligible to receive medical, dental and life insurance coverage from a subsequent employer.

(4) We do not have to “gross up” payments to the named executive officers in a termination in connection with a change of control because the other payments with respect to such termination would not be subject to the excise tax imposed by Section 4999 of the United States Internal Revenue Code.

If a named executive officer’s employment was terminated as of June 30, 2007 as a result of his death or “disability” (as described in the text below), then such executive officer (or his estate) would have been entitled to all accrued benefits, if any, as of that date.

Our obligations generally arise due to the applicable agreements and arrangements with the named executive officers providing that all outstanding equity awards and, in respect of Messrs. Schiller, Weyel and Griffin,

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accrued benefits under any and all nonqualified deferred compensation plans vest and become exercisable and non forfeitable, as applicable, upon the corresponding death or “disability” of the respective named executive officer.

In the event of a change of control, outstanding restricted stock unit awards of Messrs. Marchive and Nelson would immediately vest. Messrs. Marchive and Nelson are also entitled to the accelerated vesting of their outstanding restricted stock units upon their death or “disability”. The table below shows such effect as if such a change of control or the death or “disability” of Messrs. Marchive and Nelson had occurred as of June 30, 2007 (the value of underlying equity awards is based on the closing price of our Common Shares $6.45 on June 29, 2007 (the last trading day of our fiscal year ended June 30, 2007). For this purpose, “change of control” and “disability” each have the definition described below in the discussion of provisions of the 2006 Long-Term Incentive Plan.

Company Obligations Upon a Change of Control or Termination for Death or Disability

Name	Equity Awards
Ben Marchive	$	537,504
Steve Nelson		473,004

Each of Messrs. Schiller, Weyel and Griffin also have rights with respect to a change of control of the company, but such rights arise only in respect of a termination of their employment during a “change of control period” (as described in the text below) and the effects of such rights are reflected in Footnote (2) the “Company Obligations upon Termination” table set forth above.

Narrative Discussion to Accompany Company Obligations upon Termination and Company Obligations upon Change of Control or Termination for Death or Disability Tables

The basis for the information provided in the “Company Obligations Upon Termination” and “Company Obligations Upon Change of Control or Termination for Death or Disability” tables arises from obligations under our employment agreements with each of Messrs. Schiller, Weyel and Griffin and under the terms of restricted stock unit awards agreements with each of Messrs. Marchive and Nelson under the 2006 Long-Term Incentive Plan. The following text describes certain relevant information in regards to such obligations.

The Employment Agreements

The payments and amounts shown in the “Company Obligations upon Termination” table with respect to Messrs. Schiller, Weyel and Griffin reflect our obligations under our respective employment agreements with such individuals. Our “Severance” obligations are to make a lump sum payment on or prior to the date that is 30 days after the applicable executive officer’s last day of employment with us. Our obligations under the other columns in the table are generally to be paid (if any payment obligation exists) as they become due for the applicable executive officer. To the extent we fail to make such payments when due to the applicable executive officer, we are further obligated to pay accrued interest on such late payments at the prime or base rate of interest offered by JPMorgan Chase Bank at its offices in New York.

The provisions of the employment agreements with Messrs. Schiller, Weyel and Griffin are the same with respect to the right to receive payments and benefits. Each agreement generally provides that the types of payments and benefits shown in the “Company Obligations Upon Termination” table above for the applicable executive officers become payable or owing in respect of an “involuntary termination” of such applicable officer’s employment with us. An “involuntary termination” is defined as a termination which does not result from such executive officer’s resignation (other than a resignation by such executive officer on or before the date that is 60 days after the date upon which such executive officer receives notice of a “change in duties”), from such executive officer’s death or “disability” or from a termination by us for “cause.” Our obligations to each of Messrs. Schiller, Weyel and Griffin as reflected in the “Payments/Benefits upon Termination for Death or Disability” table arise under the employment agreements as a result of a termination in connection with his respective death or “disability.” The following definitions are applicable to the preceding description:

A “change in duties” has two separate definitions depending on whether or not the applicable event occurs during a “change of control period.” Outside of a change of control period, a change of duties occurs

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when such applicable executive officer suffers, without his consent, a material reduction in nature or scope of his authorities or duties from those previously applicable to him, a reduction in his annual base salary, or a material diminution in employee benefits and perquisites from those provided by us to executive officers with comparable duties to his. Within a change of control period, a change of duties occurs when such applicable executive officer suffers, without his consent, a material reduction in nature or scope of his authorities or duties from those applicable to him immediately prior to the date on which the change of control period begins, a reduction in his annual base salary from that provided to him immediately prior to the date on which the change of control period begins, a diminution in his eligibility to participate in bonus, stock option, incentive award or other compensation plans which provide opportunities to receive compensation that are the greater of the opportunities provided by us for executive officers with comparable duties and the opportunities under any such plans under which he was participating immediately prior to the date on which the change of control period begins, or a material diminution in employee benefits and perquisites that are the greater of the employee benefits and perquisites provided by us for executive officers with comparable duties and the employee benefits and perquisites to which he was entitled immediately prior to the date on which the change of control period begins.

• “Disability” means that, as a result of such applicable executive officer’s incapacity due to physical or mental illness, he has been absent from the full-time performance of his duties for six consecutive months and he does not return to full-time performance of his duties within 30 days after we provide him with written notice of termination.

• “Cause” has the general meaning of the applicable executive officer’s malfeasance toward us, but specifically refers in respect of such executive officers to any of the following (i) his engaging in gross negligence, gross incompetence or willful misconduct in the performance of his duties, (ii) his refusal, without proper reason, to perform his duties, (iii) his willful engagement in conduct which is materially injurious to us or our subsidiaries, (iv) his commission of an act of fraud, embezzlement or willful breach of a fiduciary duty to us or an affiliate of the ours (including specifically the disclosure of our or of an affiliates’ confidential or proprietary material information), or (v) his conviction of, or plea of no contest to, a crime involving fraud, dishonesty or moral turpitude or any felony.

• A “change of control period” under the respective employment agreements refers to a period beginning 90 days prior to the date a definitive agreement concerning a “change of control” is executed and ending on the date that is the first anniversary of the date on which such “change of control” occurs.

• A “change of control” is defined to mean the occurrence of any one of the following: (i) a merger or consolidation of the company, or sale of all or substantially all of our assets to another entity, in which either the holders of our equity securities immediately prior to such transaction do not beneficially own immediately after such transaction equity securities of the resulting entity entitled to 50% or more of the votes eligible to be cast in the election of directors or comparable governing body of the resulting entity or the persons who were members of our board of directors immediately prior to such transaction do not constitute at least a majority of the board of directors of the resulting entity immediately after such transaction (a “resulting entity” for purposes of the foregoing means the surviving or acquiring entity unless such entity is a subsidiary of another entity and the holders of the our common shares receive capital stock of such parent entity in such transaction, in which case the “resulting entity” means such parent entity), (ii) the dissolution or liquidation of the company, (iii) any person or entity, or group of persons and entities acting in concert, acquires or gains ownership or control of more than 50% of the combined voting power of our outstanding securities, or (iv) the persons who were members of our board of directors immediately before an election cease to constitute a majority of our board of directors due to or in connection with a contested election of our directors.

Restricted Stock Awards

The payments and amounts shown in the “Company Obligations upon Termination” and “Company Obligations upon Change of Control or Termination for Death or Disability” tables with respect to Messrs. Marchive and Nelson reflect our obligations under the respective restricted stock unit awards granted to such

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individuals under the 2006 Long-Term Incentive Plan. The provisions of those restricted stock unit awards are the same with respect to the right to receive payments and benefits. Each award provides that all unvested restricted stock units become vested and non forfeitable immediately upon the respective executive officer’s death or “disability” or upon a “change of control” of us Under those awards, upon vesting we are obligated to either deliver to the applicable executive officer the number of common shares underlying the award or make a cash payment of the corresponding value of such common shares, in each case within two and one-half months following the date of such vesting. Other than with respect to terminations related to the death or “disability” of the applicable executive officer, the restricted stock unit awards of each of Messrs. Marchive and Nelson do not provide these recipients with any right to specific payments in connection with a termination of his respective employment.

Under the 2006 Long-Term Incentive Plan, a “change of control” is deemed to have occurred upon any of the following events:

• any person or entity (including any group of persons or entities acting in concert) becomes the beneficial owner of our securities representing 50% or more of our voting stock then outstanding, except for person(s) or entity(ies) that are (i) us or any of our subsidiaries, (ii) any of our or our subsidiaries’ employee benefit plans, (iii) an affiliate of us, (iv) a company owned, directly or indirectly, by our shareholders in substantially the same proportion as their ownership of us, or (v) an underwriter temporarily holding securities for an offering of securities;

• the consummation of any merger, reorganization, business combination or consolidation of the company or one of our subsidiaries with or into any other company, other than any of such transactions in which the holders of our voting securities outstanding immediately prior to such transaction represent immediately after such transaction more than 50% of the combined voting power of our voting securities or the surviving company or the parent of such surviving company;

• the consummation of a sale or disposition of Energy XXI Services, LLC, the subsidiary through which we generally employ our employees, or of all or substantially all of our assets, other than (i) a sale or disposition where the holders of our voting securities outstanding immediately prior to such transaction hold securities immediately after such transaction representing more than 50% of the combined voting power of the voting securities of the acquirer, or parent of the acquirer; or

• individuals who constituted our board of directors as of October 6, 2006 cease to constitute at least a majority of our board of directors, except that any individual who becomes a director subsequent to such date whose election to the board of directors was approved by a vote of at least a majority of our directors (including those that comprised such initial board and those that are subsequently elected per such exception, but excluding any individual who initially joins our board of directors as a result of a contest for the election or removal of any of our directors or otherwise as a result of other solicitation of proxies or consents by or on behalf of a person other than our board of directors) shall be considered as if such person(s) were initially members of our board of directors as of such October 6, 2006 date.

Notwithstanding the foregoing, the definition of “change of control” under the 2006 Long-Term Incentive Plan is expressly intended to comply with the requirements of Section 409A of the United States Internal Revenue Code and such plan contemplates that the definition will be modified to the extent necessary to ensure compliance with such requirements.

“Disability” is defined in respect of Messrs. Marchive’s and Nelson’s restricted stock unit awards as the applicable recipient’s inability to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, of such recipient is, by reason of any such an impairment, receiving income replacement benefits for a period of not less than three months under and accident and health plan covering employees of Energy XXI Services, LLC.

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Other Benefits

Each of the named executive officers would also be eligible for other benefits and compensation accrued through the date of their respective termination on the same basis as generally available to the other employees of the Company, including the fact that they would be fully vested in any profit sharing or other nonqualified deferred compensation that would have previously been paid by us. Nevertheless, the occurrence of such named executive officer’s termination or a change of control would not create any additional rights in these respects.

Compensation Committee Interlocks and Insider Participation

None of the members of the Remuneration Committee is or has been an officer or employee of the Company. None of the Company’s executive officers currently serves on the Remuneration Committee or any similar committee of another public company.

Mr. Schiller, our Chairman of the Board and Chief Executive Officer, participated in deliberations concerning executive compensation, although he was not responsible for the final determination of his compensation.

Director Compensation

Our directors who are also employees of the company do not receive compensation for serving on the board or any of its committees. The following table and narrative disclosure provide information on our compensation for non-employee directors for our fiscal year ended June 30, 2007.

Name	Fees Earned or Paid in Cash(1)		Stock Awards(2)		All Other Compensation(3)		Total
William Colvin	$	52,404	$	18,000	$	26,202	$	96,606
Paul Davison		7,033		5,600		3,516		16,149
David M. Dunwoody		43,819		18,000		21,911		83,730
Hill A. Feinberg		8,544		5,600		4,272		18,416

(1) The amounts shown reflect the fees earned by each non executive director. However, each of the non executive directors elected to forego all cash compensation earned during the fiscal year ended June 30, 2007 and receive Common Shares with a market value equal to 150% of such cash compensation in accordance with the Company’s director compensation plan. The amount reflecting the 50% of market value in excess of the cash compensation earned is reflected in the “All Other Compensation” column of the table.

(2) The amounts shown reflect the compensation cost related to restricted share awards included in the Company’s financial statements for the fiscal year ended June 30, 2007. The grant date fair value of each of the awards, as determined pursuant to FAS 123R, on a per share basis was $5.03 for Messrs. Colvin and Dunwoody, respectively, and $4.78 for Messrs. Davison and Feinberg, respectively. For a discussion of the valuation assumptions used in calculating the compensation cost for the requisite service period and the grant date fair value of each of the awards, see the description under “Executive Compensation — Compensation Discussion and Analysis — Elements of Compensation — Material Tax and Accounting Considerations” set forth later in this document.

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The fiscal year 2007 restricted share awards were granted to each of Messrs. Colvin, Davison, Dunwoody and Feinberg in the respective share amounts as follows:

Name	Date of Grant		Number of Restricted Shares
William Colvin		October 5, 2006		6,000
David M. Dunwoody		October 5, 2006		6,000
Paul Davison		May 7, 2007		3,000
Hill A. Feinberg		May 7, 2007		3,000

As of the end of the fiscal year ended June 30, 2007, the rights of each of the non executive directors in the restricted share awards had not fully vested and there were the following outstanding restricted share awards for these directors: 1,500 restricted shares for each of Messrs. Colvin and Dunwoody and 2,000 restricted shares for each of Messrs. Davison and Feinberg.

(3) Amounts shown reflect the 50% of market value of Common Shares that each of the non executive directors received by electing to forego their respective cash compensation earned during the fiscal year ended June 30, 2007 and to receive Common Shares with a market value equal to 150% of such cash compensation in lieu thereof. In respect of such election, during fiscal year 2007, we delivered to each of Messrs. Colvin, Davison, Dunwoody and Feinberg 15,382, 1,729, 12,782 and 2,101 common shares, respectively, with an average per common share value of $5.11, $6.10, $5.14 and $6.10, respectively.

In October 2006, our board adopted a non-executive director remuneration plan. This plan compensates our non-employee directors as follows:

• an annual cash retainer of $30,000, payable quarterly;

• an annual restricted share award of 6,000 shares of our common stock;

• additional cash retainer of $2,500 per board meeting attended;

• additional cash retainer of $1,500 per committee meeting attended;

• an additional annual cash retainer of $15,000 for the chairman of the Audit Committee; and

• an additional annual cash retainer of $10,000 for the chairman of any committee other than the Audit Committee.

The director remuneration plan also allows each director to receive common stock in lieu of any cash payment for board or committee services. To the extent any director makes this election, the director is entitled to receive common shares with a market value equal to 150% of the equivalent cash compensation foregone. We also provide our directors liability insurance policies.

Remuneration Committee Interlocks and Insider Participation

The members of our Remuneration Committee of the board of directors during the fiscal year ended June 30, 2007 were Mr. Dunwoody, Chairman, and Messrs. Colvin, Davison and Feinberg, none of whom is or has been an officer or employee of the company. Mr. Schiller, our Chairman of the Board and Chief Executive Officer, participated in deliberations [of the Remuneration Committee] concerning executive compensation, except with respect to himself.

Director Agreements

As part of the start up of the Company, we entered into non executive appointment letters dated August 31, 2005 with Messrs. Colvin and Dunwoody. Under the terms of these letters, Messrs. Colvin and Dunwoody agreed to act as non executive directors of the Company for a period of three years, although the term of service may be terminated by either party on one-month’s prior written notice. On May 7, 2007, we also entered into non executive appointment letters with Messrs. Davison and Feinberg. Under his letter, Mr. Davison agreed to act as a non executive director of the Company for a period of three years, with his continued service subject to his election at the Annual Stockholders’ Meeting for fiscal year 2007 and the right of termination by either party on one-month’s prior written notice. Mr. Feinberg similarly agreed to act as a non

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executive director for a period of two years, with his continued service likewise subject to election at the Annual Stockholders’ Meeting for fiscal year 2007 and the right of termination by either party on one-month’s prior written notice. The compensation under these appointment letters is consistent with the director plan.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Our Parent assumed certain contracts and obligations relating to its 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 Parent’s expenses, including initial public offering expenses, for which our Parent subsequently reimbursed TEC. TEC charged no fees or interest for this service.

Furthermore, from October 20, 2005 through 2006 our Parent 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. Our Parent 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 Parent’s restricted common stock and warrants trade on the AIM Exchange under the symbol “EXXS” and “EGYW”. On June 6, 2007 our Parent’s common stock was admitted to the CREST electronic settlement system, which allows any interested party to trade our Parent’s unrestricted common stock under the symbol “EXXI”. Our Parent’s restricted common stock will continue to trade under the symbol “EXXS”. On June 1, 2007, our Parent commenced trading in the United States on the OTCBB. On August 1, 2007, our Parent’s common stock was admitted for trading on NASDAQ under the symbol “EXXI”. Since trading commenced in the United States, the high and low sale prices of our Parent’s common stock have been $6.75 and $5.05, 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	$	6.05	$	6.44	$	1.58	$	4.78	$	5.25	$	0.63
September 30, 2007 (through August 17, 2007)	$	6.05	$	6.67	$	1.68	$	5.78	$	5.15	$	1.57

As of August 17, 2007, there were approximately 478 holders of our Parent’s common stock and 62 holders of warrants. Our Parent has never paid dividends on our common stock and intends to retain its cash flow from operations, for the future operation and development of our business. In addition, our Parent’s primary credit facility and the terms of our outstanding subordinated debt prohibit the payment of cash dividends on its common stock.

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DESCRIPTION OF THE NEW NOTES

You can find the definitions of certain terms used in this description under the subheading “ — Certain Definitions.” In this description, the term “Company,” “us” or “we” refers only to Energy XXI Gulf Coast, Inc. (including its permitted successors and assigns) and not to any of its subsidiaries. The term “Parent” refers to Energy XXI (Bermuda) Limited, the ultimate parent of the Company including its permitted successors and assigns). References to the “notes” in this “Description of the New Notes” include both the old notes and the new notes.

The Company will issue the new notes, and the old notes were issued, under an indenture, dated as of June 8, 2007, among itself, the Parent, the other Guarantors and Wells Fargo Bank, National Association, as trustee. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939.

The following description is a summary of the material provisions of the indenture and the Registration Rights Agreement. It does not restate those agreements in their entirety. We urge you to read the indenture and the registration rights agreement because they, and not this description, define your rights as holders of the notes. Certain defined terms used in this description but not defined below under “ — Certain Definitions” have the meanings assigned to them in the indenture.

The registered Holder of a note will be treated as the owner of it for all purposes. Only registered Holders will have rights under the indenture.

Brief Description of the Notes and the Guarantees

The Notes

The notes:

• will be general unsecured senior obligations of the Company;

• will be initially issued in an aggregate principal amount of $750.0 million, subject to the Company’s ability to issue additional notes under certain circumstances;

• will be equal in right of payment to all existing and future senior Indebtedness of the Company;

• will be effectively subordinate in right of payment to any secured Indebtedness of the Company to the extent of the collateral therefor, including Indebtedness under the Company’s existing and future Credit Facilities;

• will be senior in right of payment to any future subordinated Indebtedness of the Company;

• will be fully and unconditionally, jointly and severally, guaranteed by the Guarantors; and

• held by QIBs will be eligible for trading on The PORTAL^SM Market.

We have agreed to use reasonable efforts to list the notes on the official list of the Luxembourg Stock Exchange and have the notes admitted to trading on the EuroMTF or another European stock exchange, but there can be no assurance that the notes will be accepted for listing on any such exchange.

The Guarantees

The notes will be jointly and severally, fully and unconditionally, guaranteed by the Parent and each of the Company’s present Restricted Subsidiaries and its future Material Domestic Subsidiaries.

The Guarantees of the notes:

• will be general unsecured senior obligations of each Guarantor;

• will be equal in right of payment to all existing and future senior Indebtedness of each Guarantor;

• will be effectively subordinate in right of payment to any secured Indebtedness of each Guarantor to the extent of the collateral therefor, including guarantees or other Indebtedness of the Guarantors under the Company’s existing and future Credit Facilities; and

• will be senior in right of payment to any future subordinated Indebtedness of each Guarantor.

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Any debt outstanding under the Company’s first lien revolving Credit Facility will be secured.

As of the date of the indenture, all of our subsidiaries will be “Restricted Subsidiaries.” However, under the circumstances described below under the subheading “ — Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries,” we will be permitted to designate certain of our subsidiaries as “Unrestricted Subsidiaries.” Our Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. Our Unrestricted Subsidiaries will not guarantee the notes.

Principal, Maturity and Interest

The Company will issue the notes with an initial maximum aggregate principal amount of $750.0 million. The Company may issue additional notes from time to time after this offering. Any offering of additional notes is subject to the covenant described below under the caption “ — Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock.” The notes and any additional notes subsequently issued under the indenture, will be treated as a single class for all purposes under the indenture, including without limitation, waivers, amendments, redemptions and offers to purchase. The Company will issue notes in denominations of $2,000 and integral multiples of $2,000. The notes will mature on June 15, 2013.

Interest on the notes will accrue at the rate of 10% per annum. Interest will be payable semi-annually in arrears on June 15 and December 15, commencing on December 15, 2007. The Company will make each interest payment to the Holders of record on the immediately preceding June 1 and December 1.

Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Additional interest may accrue on the notes as liquidated damages in certain circumstances described below under “ — Registration Rights; Additional Interest,” and all references to “interest” in this description include any additional interest that may be payable on the notes, including, but not limited to, any additional interest payable pursuant to the Registration Rights Agreement or pursuant to clause (5) under the heading “Events of Default.” In the case of the new notes, all interest accrued on the outstanding notes from June 8, 2007 will be treated as having accrued on the new notes that are issued in exchange for the old notes. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Methods of Receiving Payments on the Notes

If a Holder has given wire transfer instructions to the Company, the Company will pay all principal, interest and premium, if any, on that Holder’s notes in accordance with those instructions. All other payments on notes will be made at the office or agency of the paying agent and registrar unless the Company elects to make interest payments by check mailed to the Holders at their address set forth in the register of Holders.

Paying Agent and Registrar for the Notes

The trustee will initially act as paying agent and registrar. The Company may change the paying agent or registrar without prior notice to the Holders of the notes, and the Company or any of its domestic Subsidiaries may act as paying agent.

Listing

If that application is successful, and for so long as the notes are listed on the official list of the Luxembourg Stock Exchange and admitted to trading on the regulated market of the Luxembourg Stock Exchange and the rules of the Luxembourg Stock Exchange so require, the Company will make available the notices to the public in written form at places indicated by announcements to be published in a leading newspaper having a general circulation in Luxembourg (which is expected to be the d’Wort) or on the website of the Luxembourg Stock Exchange, www.bourse.lu, or by other means considered equivalent by the Luxembourg Stock Exchange. The Company shall also ensure that notices are duly published in a manner that complies with the rules and regulations of any other stock exchange and/or markets and/or alternative trading system or multilateral trading facility on which the notes are for the time being listed. We will agree to comply with any comparable requirements on another European stock exchange if we list the notes there.

Guarantees

Initially, the Parent and all of the Company’s Subsidiaries will guarantee the notes. In the future, the notes will be guaranteed by each of the Company’s future Material Domestic Subsidiaries. See “ — Certain

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Covenants — Additional Guarantees.” These additional Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Guarantee will be limited as necessary to prevent that Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors — Risks Relating to the Notes — A court could cancel the guarantees under fraudulent conveyance laws or certain other circumstances.”

A Guarantor may not sell or otherwise dispose of all or substantially all of its properties or assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person), another Person, other than the Company or another Guarantor, unless:

(1) immediately after giving effect to such transaction, no Default or Event of Default exists; and

(2) either:

(a) the Person acquiring the properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than the Guarantor) unconditionally assumes all the obligations of that Guarantor, pursuant to a supplemental indenture substantially in the form specified in the indenture, under the notes, the indenture and that Guarantor’s Guarantee and the Registration Rights Agreement on terms set forth therein; or

(b) such sale or other disposition complies with the “Asset Sale” provisions of the indenture.

The Guarantee of a Guarantor will be released:

(1) with respect to Guarantees by the Company’s Subsidiaries, in connection with any sale or other disposition of all or substantially all of the properties or assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) a Subsidiary of the Company, if the sale or other disposition complies with the “Asset Sale” provisions of the indenture; or

(2) in connection with any sale or other disposition of all of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) a Subsidiary of the Company, if the sale or other disposition complies with the “Asset Sale” provisions of the indenture; or

(3) if the Company designates any Restricted Subsidiary that is a Guarantor as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture; or

(4) upon Legal Defeasance or Covenant Defeasance with respect to all notes as described below under the caption “ — Legal Defeasance and Covenant Defeasance” or upon satisfaction and discharge of the indenture as described below under the caption “ — Satisfaction and Discharge.”

See “ — Repurchase at the Option of Holders — Asset Sales.”

Optional Redemption

On or after June 15, 2010, the Company may redeem all or a part of the notes at any time or from time to time upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest thereon, if any, on the notes to the applicable redemption date, if redeemed during the twelve-month period beginning on June 15 of the years set forth below:

Period	Percentage
2010		105.000
2011		102.500
2012 and thereafter		100.000 %

In addition, at any time on or prior to June 15, 2010 the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the notes issued under the indenture at a redemption price of 110% of the principal amount, plus accrued and unpaid interest, if any, on the notes to the redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on an interest

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payment date that is on or prior to the redemption date), with the net cash proceeds of one or more Equity Offerings by the Company, provided that:

(1) at least 65% of the aggregate principal amount of notes issued under the indenture (including additional notes) remains outstanding immediately after the occurrence of such redemption (excluding notes held by the Company and its Subsidiaries); and

(2) the redemption occurs within 90 days of the date of the closing of such Equity Offering.

In addition, at any time prior to June 15, 2010, the notes may be redeemed in whole or in part at the option of the Company upon not less than 30 nor more than 60 days’ prior notice at a redemption price equal to 100% of the principal amount thereof plus the Applicable Premium as of, and accrued and unpaid interest, if any, to the date of redemption (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

“Applicable Premium” means, with respect to a note at any redemption date, the greater of (x) 1.0% of the principal amount of such note and (y) the excess of (A) the present value at such time of (1) redemption price of such note as of June 15, 2010 (without regard to accrued and unpaid interest) plus (2) all required interest payments due on such note through June 15, 2010, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the principal amount of such note.

“Treasury Rate” means, with respect to the notes as of any redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the period from the redemption date to June 15, 2010; provided, however, that if the period from the redemption date to June 15, 2010 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to the final maturity of the notes is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

Except as provided above, the notes will not be redeemable at the Company’s option prior to their final maturity.

Selection and Notice

If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption as follows:

(1) if the relevant notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which the notes are listed; or

(2) if the relevant notes are not listed on any national securities exchange, on a pro rata basis.

No notes of $1,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each Holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture. Notices of redemption may not be conditional.

If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the Holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of them called for redemption.

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Mandatory Redemption; Open Market Purchases

Except as set forth below under “ — Repurchase at the Option of Holders,” the Company is not required to make mandatory redemption or sinking fund payments with respect to the notes or to repurchase the notes at the option of the Holders. The Company may at any time and from time to time purchase notes in the open market or otherwise if such purchase complies with the then applicable agreements of the Company, including the indenture.

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, each Holder of notes will have the right to require the Company to repurchase all or any part (equal to $1,000 or an integral multiple of $1,000) of that Holder’s notes pursuant to a Change of Control Offer on the terms set forth in the indenture. In the Change of Control Offer, the Company will offer a Change of Control Payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest, if any, on the notes repurchased, to the date of settlement (the “Change of Control Purchase Date”), subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the Change of Control Purchase Date. Within 30 days following any Change of Control, the Company will mail a notice to each Holder and the Trustee describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes as of the Change of Control Purchase Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such conflict.

On the Change of Control Purchase Date, the Company will, to the extent lawful:

(i) accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;

(ii) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

(iii) deliver or cause to be delivered to the trustee the notes properly accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by the Company.

On the Change of Control Purchase Date, the paying agent will mail to each Holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each Holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each new note will be in a principal amount of $1,000 or an integral multiple of $1,000. The Company will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

The occurrence of a Change of Control may result in a default under the Company’s existing or future Credit Facilities and may cause a default under other Indebtedness of Parent and its Subsidiaries or the Company and its Subsidiaries, and give the lenders thereunder the right to require the Company to repay obligations outstanding thereunder. Moreover, the exercise by Holders of their right to require the Company or Parent to repurchase the notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. The Company’s ability to repurchase notes following a Change of Control also may be limited by the Company’s then existing financial resources. Prior to complying with any of the provisions of this “Change of Control” covenant, but in any

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event no later than the Change of Control Purchase Date, the Company will, to the extent necessary, either repay all outstanding Credit Facilities or obtain any requisite consents under all agreements governing outstanding Credit Facilities to permit the repurchase of notes required by this covenant.

The provisions described above that require the Company to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the Holders of the notes to require that the Company repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

The Company will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by the Company and purchases all notes properly tendered and not withdrawn under the Change of Control Offer.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of the Parent and its subsidiaries, taken as a whole, the Company or any of the Company’s Restricted Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a Holder of notes to require the Company to repurchase the notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Parent and its subsidiaries taken as a whole, the Company, or any of the Company’s Restricted Subsidiaries taken as a whole to another Person or group may be uncertain.

Asset Sales

The Company will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1) the Company (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the fair market value of the assets or Equity Interests issued or sold or otherwise disposed of;

(2) the fair market value is determined by the Company’s Board of Directors and evidenced by a resolution of the Board of Directors set forth in an officers’ certificate delivered to the trustee; and

(3) at least 75% of the consideration received by the Company or such Restricted Subsidiary from all Asset Sales since the Issue Date, in the aggregate, is in the form of cash.

For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities, as shown on the Company’s or such Restricted Subsidiary’s most recent balance sheet, of the Company or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases the Company or such Restricted Subsidiary from further liability; and

(b) any securities, notes or other obligations received by the Company or any such Restricted Subsidiary from such transferee that are converted within 90 days by the Company or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion.

Within 360 days after the receipt of any Net Proceeds from an Asset Sale, the Company or any such Restricted Subsidiary may apply those Net Proceeds at its option to any combination of the following:

(i) to repay, redeem or repurchase Indebtedness under a Credit Facility; provided that if such Indebtedness is revolving credit Indebtedness, to correspondingly reduce commitments with respect thereto as specified in the covenant entitled “Incurrence of Indebtedness and Issuance of Preferred Stock”;

(ii) to acquire all or substantially all of the properties or assets of one or more other Persons primarily engaged in the Oil and Gas Business, and, for this purpose, a division or line of business of a

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Person shall be treated as a separate Person so long as such properties and assets are acquired by the Company or a Restricted Subsidiary;

(iii) to acquire a majority of the Voting Stock of one or more other Persons primarily engaged in the Oil and Gas Business, if after giving effect to any such acquisition of Voting Stock, such Person is or becomes a Restricted Subsidiary;

(iv) to make one or more capital expenditures; or

(v) to acquire other long-term assets that are used or useful in the Oil and Gas Business.

Pending the final application of any Net Proceeds, the Company or any such Restricted Subsidiary may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture.

Any Net Proceeds from Asset Sales that are not applied or invested as provided in the preceding paragraph will constitute “Excess Proceeds.” On the 361st day after the Asset Sale (or, at the Company’s option, any earlier date), if the aggregate amount of Excess Proceeds then exceeds $15.0 million, the Company will make an Asset Sale Offer to all Holders of notes, and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets, to purchase the maximum principal amount of notes and such other pari passu Indebtedness that may be purchased out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of principal amount plus accrued and unpaid interest, if any, to the date of settlement, subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of settlement, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, the Company may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and other pari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such other pari passu Indebtedness to be purchased on a pro rata basis. Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

The exercise by Holders of notes of their right to require the Company to repurchase the notes upon an Asset Sale could cause a default under our first lien revolving credit facility if the Company is then prohibited by the terms of the first lien revolving credit facility from making the Asset Sale Offer under the indenture. In the event an Asset Sale occurs at a time when the Company is prohibited from purchasing notes, the Company could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If the Company does not obtain a consent or repay those borrowings, it will remain prohibited from purchasing notes. In that case, the Company’s failure to purchase tendered notes would constitute an Event of Default under the indenture, which could, in turn, constitute a default under the other indebtedness, including the first lien revolving credit agreement.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such conflict.

Certain Covenants

Restricted Payments

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of the Company’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Company’s or any of its Restricted Subsidiaries’

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Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Company or payable to the Company or a Restricted Subsidiary of the Company);

(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Company) any Equity Interests of the Company or any direct or indirect parent of the Company;

(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness that is subordinated to the notes or the Guarantees, except a payment of interest or principal at the Stated Maturity thereof; or

(4) make any Restricted Investment (all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as “Restricted Payments”),

unless, at the time of and after giving effect to such Restricted Payment:

(1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;

(2) the Company would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “ — Incurrence of Indebtedness and Issuance of Preferred Stock;” and

(3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and its Restricted Subsidiaries after the date of the indenture (excluding Restricted Payments permitted by clauses (2), (3), (4), (6), (7), (8), (9) and (10) of the next succeeding paragraph), is less than the sum, without duplication, of:

(a) 50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from April 1, 2007 to the end of the Company’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus

(b) 100% of the aggregate net cash proceeds received by the Company (including the fair market value of any Additional Assets to the extent acquired in consideration of Equity Interests of the Company (other than Disqualified Stock)) since the Issue Date as a contribution to its common equity capital or from the issue or sale of Equity Interests of the Company (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of the Company that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of the Company), plus

(c) to the extent that any Restricted Investment that was made after the Issue Date is sold for cash or otherwise liquidated or repaid for cash, the lesser of (i) the cash return of capital with respect to such Restricted Investment (less the cost of disposition, if any) and (ii) the initial amount of such Restricted Investment, plus

(d) to the extent that any Unrestricted Subsidiary of the Company is redesignated as a Restricted Subsidiary after the Issue Date, the lesser of (i) the fair market value of the Company’s Investment in such Subsidiary as of the date of such redesignation or (ii) such fair market value as of the date on which such Subsidiary was originally designated as an Unrestricted Subsidiary.

So long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the preceding provisions will not prohibit:

(1) the payment of any dividend within 60 days after the date of declaration of the dividend, if at the date of declaration the dividend payment would have complied with the provisions of the indenture;

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(2) the redemption, repurchase, retirement, defeasance or other acquisition of any subordinated Indebtedness of the Company or any Guarantor or of any Equity Interests of the Company in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of the Company) of, Equity Interests of the Company (other than Disqualified Stock); provided that the amount of any such net cash proceeds that are utilized for any such redemption, repurchase, retirement, defeasance or other acquisition will be excluded from clause (3)(b) of the preceding paragraph;

(3) the defeasance, redemption, repurchase, retirement or other acquisition of subordinated Indebtedness of the Company or any Guarantor with the net cash proceeds from an incurrence of, or in exchange for, Permitted Refinancing Indebtedness; and

(4) the payment of any dividend by a wholly-owned Restricted Subsidiary of the Company to the Company or a Restricted Subsidiary;

(5) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Company or any Restricted Subsidiary of the Company held by any current or former director or employee of the Company or any of its Restricted Subsidiaries pursuant to any director or employee equity subscription agreement or plan, stock option agreement or similar agreement or plan; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $2.0 million in any twelve-month period;

(6) the acquisition of Equity Interests by the Company in connection with the exercise of stock options or stock appreciation rights by way of cashless exercise;

(7) so long as no Default has occurred and is continuing, upon the occurrence of a Change of Control or an Asset Sale and within 60 days after the completion of the offer to repurchase the notes under the covenants described under “ — Repurchase at the Option of Holders — Change of Control” or “ — Asset Sales” above (including the purchase of all notes tendered), any purchase, repurchase, redemption, defeasance, acquisition or other retirement for value of Subordinated Indebtedness required under the terms thereof as a result of such Change of Control or Asset Sale at a purchase or redemption price not to exceed 101% of the outstanding principal amount thereof, plus accrued and unpaid interest thereon, if any, provided that, in the notice to Holders relating to a Change of Control or Asset Sale hereunder, the Company shall describe this clause (7);

(8) the payment of cash in lieu of fractional shares of Capital Stock in connection with any transaction otherwise permitted under the indenture;

(9) Permitted Payments to Parent Companies; and

(10) other Restricted Payments in an aggregate amount since the Issue Date not to exceed $20.0 million.

The amount of all Restricted Payments (other than cash) will be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The fair market value of any assets or securities that are required to be valued by this covenant will be determined by the Board of Directors, whose determination shall be evidenced by a Board Resolution. The Board of Directors’ determination must be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if the fair market value exceeds $20.0 million. Not later than the date of making any Restricted Payment under the first paragraph of this covenant the Company will deliver to the trustee an officers’ certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by this “Restricted Payments” covenant were computed, together with a copy of any fairness opinion or appraisal required by the indenture. For purposes of determining compliance with this “Restricted Payments” covenant, in the event that a Restricted Payment meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1)-(10), the Company will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such Restricted Payment in any manner that complies with this covenant.

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Incurrence of Indebtedness and Issuance of Preferred Stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), neither the Company nor any Guarantor (other than Parent) will issue any Disqualified Stock, and the Company will not permit any of its other Restricted Subsidiaries to issue any shares of preferred stock; provided, however, that the Company and any Guarantor (other than Parent) may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, if the Fixed Charge Coverage Ratio for the Company’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock is issued would have been at least 2.5 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or Disqualified Stock had been issued, as the case may be, at the beginning of such four-quarter period.

The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Debt”):

(1) the incurrence by the Company or any Guarantor of additional Indebtedness (including letters of credit) under one or more Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of the Company and its Subsidiaries thereunder) not to exceed an amount equal to the greater of (a) $400.0 million, less the aggregate amount of all Net Proceeds of Asset Sales applied by the Company or any of its Restricted Subsidiaries since the Issue Date to repay any revolving credit Indebtedness under any Credit Facilities and effect a corresponding commitment reduction thereunder pursuant to the covenant described above under the caption “Asset Sales,” and (b) 30% of ACNTA as of the date of such incurrence;

(2) the incurrence by the Company or any of its Restricted Subsidiaries of the Existing Indebtedness;

(3) the incurrence by the Company and the Guarantors of Indebtedness represented by the notes issued and sold in this offering and the related Guarantees to be issued on the date of the indenture and the Exchange Notes and the related Guarantees issued pursuant to the Registration Rights Agreement;

(4) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvement of property, plant or equipment used in the business of the Company or such Restricted Subsidiary, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to refund, refinance or replace any Indebtedness incurred pursuant to this clause (4), not to exceed the greater of $10.0 million at any time outstanding;

(5) the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to refund, refinance or replace Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clause (2), (3) or (12) of this paragraph or this clause (5);

(6) the incurrence by the Company or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries; provided, however, that:

(a) if the Company is the obligor on such Indebtedness and a Guarantor is not the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the notes, or if a Guarantor is the obligor on such Indebtedness and neither the Company nor another Guarantor is the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the Guarantee of such Guarantor; and

(b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness

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being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person that is neither the Company nor a Restricted Subsidiary of the Company will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the incurrence by the Company or any of its Restricted Subsidiaries of Hedging Obligations;

(8) the guarantee by the Company or any of the Guarantors of Indebtedness of the Company or any Guarantor that was permitted to be incurred by another provision of this covenant;

(9) the incurrence by the Company or any of its Restricted Subsidiaries of obligations relating to net gas balancing positions arising in the ordinary course of business and consistent with past practice;

(10) the incurrence by the Company’s Unrestricted Subsidiaries of Non-Recourse Debt, provided, however, that if any such Indebtedness ceases to be Non-Recourse Debt of an Unrestricted Subsidiary, such event will be deemed to constitute an incurrence of Indebtedness by a Restricted Subsidiary of the Company that was not permitted by this clause (10);

(11) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness in respect of bid, performance, surety and similar bonds issued for the account of the Company and any of its Restricted Subsidiaries in the ordinary course of business, including guarantees and obligations of the Company and any of its Restricted Subsidiaries with respect to letters of credit supporting such obligations (in each other than an obligation for money borrowed);

(12) Indebtedness of a Restricted Subsidiary incurred and outstanding on the date on which such Restricted Subsidiary was acquired by, or merged into, the Company or any Restricted Subsidiary (other than Indebtedness Incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was otherwise acquired by the Company or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that at the time such Restricted Subsidiary is acquired by the Company, the Company would have been able in Incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant after giving effect to the incurrence of such Indebtedness pursuant to this clause (12);

(13) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness arising from agreements of the Company or any of its Restricted Subsidiaries providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or Capital Stock of a Subsidiary, provided that the maximum aggregate liability in respect of all such Indebtedness shall at no time exceed the gross proceeds actually received by the Company and its Restricted Subsidiaries in connection with such disposition; and

(14) the incurrence by the Company or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, not to exceed $25.0 million.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of Indebtedness (including Acquired Debt) meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (14) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such item of Indebtedness in any manner that complies with this covenant.

The amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP. Indebtedness of any Person existing at the time such Person becomes a Restricted Subsidiary shall be deemed to have been incurred by the Company and the Restricted Subsidiary at the time such Person becomes a Restricted Subsidiary. The accrual of interest, the accretion or amortization of original issue discount, the payment of interest

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on any Indebtedness in the form of additional Indebtedness with the same terms, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; provided, in each such case, that the amount thereof is included in Fixed Charges of the Company as accrued.

Liens

The Company will not and will not permit any of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness or Attributable Debt upon any of their property or assets, now owned or hereafter acquired, unless the notes or any Guarantee of such Restricted Subsidiary, as applicable, is secured on an equal and ratable basis (or on a senior basis to, in the case of obligations subordinated in right of payment to the notes or such Guarantee, as the case may be) with the obligations so secured until such time as such obligations are no longer secured by a Lien.

Dividend and Other Payment Restrictions Affecting Subsidiaries

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock to the Company or any of its Restricted Subsidiaries, or pay any Indebtedness or other obligations owed to the Company or any of its Restricted Subsidiaries;

(2) make loans or advances to the Company or any of its Restricted Subsidiaries; or

(3) transfer any of its properties or assets to the Company or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements governing Existing Indebtedness and Credit Facilities as in effect on the date of the indenture and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of those agreements, provided that the amendments, modifications, restatements, renewals, increases, supplements, refundings, replacement or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the date of the indenture;

(2) the indenture, the notes and the Guarantees;

(3) applicable law;

(4) any instrument governing Indebtedness or Capital Stock of a Person acquired by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition, which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired, provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;

(5) customary non-assignment provisions in leases entered into in the ordinary course of business and consistent with past practices;

(6) purchase money obligations for property acquired in the ordinary course of business that impose restrictions on that property of the nature described in clause (3) of the preceding paragraph;

(7) any agreement for the sale or other disposition of a Restricted Subsidiary of the Company that restricts distributions by that Restricted Subsidiary pending its sale or other disposition;

(8) Permitted Refinancing Indebtedness, provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

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(9) agreements governing other Indebtedness of the Company and one or more Restricted Subsidiaries permitted under the indenture, provided that the restrictions in the agreements governing such Indebtedness are not materially more restrictive, taken as a whole, than those in the indenture;

(10) Liens securing Indebtedness otherwise permitted to be incurred under the provisions of the covenant described above under the caption “ — Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

(11) provisions with respect to the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, stock sale agreements, agreements respecting Permitted Business Investments and other similar agreements entered into in the ordinary course of business; and

(12) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business.

Merger, Consolidation or Sale of Assets

The Company will not, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not the Company is the surviving corporation); or (2) sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the properties or assets of the Company and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person, unless:

(1) either (a) the Company is the surviving corporation; or (b) the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made is a corporation organized or existing under the laws of the United States, any state of the United States or the District of Columbia;

(2) the Person formed by or surviving any such consolidation or merger (if other than the Company) or the Person to which such sale, assignment, transfer, lease, conveyance or other disposition has been made assumes all the obligations of the Company under the notes, the indenture and the Registration Rights Agreement pursuant to agreements reasonably satisfactory to the trustee;

(3) immediately after such transaction no Default or Event of Default exists;

(4) except with respect to a transaction solely between the Company and a Guarantor, the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made will, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “ — Incurrence of Indebtedness and Issuance of Preferred Stock”; and

(5) the Company shall have delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and such supplemental indenture (if any) comply with the indenture.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the properties or assets of a Person.

Transactions with Affiliates

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate (each, an “Affiliate Transaction”), unless:

(1) the Affiliate Transaction is on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person; and

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(2) the Company delivers to the trustee:

(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $10.0 million, a resolution of the Board of Directors set forth in an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors; and

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $25.0 million, the Company delivers to the Trustee a written opinion that such Affiliate Transaction(s) is fair, from a financial point of view, to the Company and its Restricted Subsidiaries, taken as a whole, or that such Affiliate Transaction(s) is not less favorable to the Company and its Restricted Subsidiaries than could reasonably be expected to be obtained at the time in an arm’s-length transaction with a person who is not an Affiliate, in either such case issued by an independent accounting, appraisal or investment banking firm of national standing.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1) any employment or severance agreement or other employee compensation agreement, arrangement or plan, or any amendment thereto, entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business;

(2) transactions between or among any of the Parent, the Company and its Restricted Subsidiaries;

(3) transactions with a Person (other than an Unrestricted Subsidiary of the Company) that is an Affiliate of the Company solely because the Company owns an Equity Interest in such Person;

(4) the payment of reasonable directors’ fees, payments, the payments of other reasonable benefits and the provision of officers’ and directors’ indemnification and insurance to the extent permitted by law to persons who are officers and directors of the Parent or its Subsidiaries and the Company and its Restricted Subsidiaries and who are not otherwise Affiliates of the Company, in each case in the ordinary course of business and approved by the Board of Directors;

(5) sales of Equity Interests (other than Disqualified Stock) to Affiliates of the Company;

(6) transactions among the Company, its Restricted Subsidiaries and Energy XXI Services, Inc. (“Services”), a wholly-owned subsidiary of Parent and a sister company of the Company relating to the provision of employment, administrative and related services by Services pursuant to the Cost Allocation Agreement in effect on the Issue Date among the Company, certain Subsidiaries and Services, as such agreement may be amended, modified or supplemented from time to time provided that any such amendment, modification or supplement will not be materially adverse to the Company or the Restricted Subsidiaries compared to the terms of such agreement in effect on the Issue Date; and

(7) Restricted Payments that are permitted by the provisions of the indenture described above under the caption “ — Restricted Payments,” including Permitted Payments to Parent Companies.

Designation of Restricted and Unrestricted Subsidiaries

The Board of Directors of the Company may designate any Restricted Subsidiary of the Company to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary of the Company is designated as an Unrestricted Subsidiary, the aggregate fair market value of all outstanding Investments owned by the Company and its Restricted Subsidiaries in the Subsidiary properly designated will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the first paragraph of the covenant described above under the caption “ — Restricted Payments” or represent Permitted Investments, as determined by the Company. That designation will only be permitted if the Investment would be permitted at that time and if the Subsidiary so designated otherwise meets the definition of an Unrestricted Subsidiary.

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The Board of Directors of the Company may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of the Company; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company of any outstanding Indebtedness of such Unrestricted Subsidiary and the creation, incurrence, assumption or otherwise causing to exist any Lien of such Unrestricted Subsidiary and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described above under the caption “ — Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period, (2) such Lien is permitted under the covenant described above under the caption “ — Liens” and (3) no Default or Event of Default would be in existence following such designation.

Additional Guarantees

If the Company or any of its Restricted Subsidiaries acquires or creates another Material Domestic Subsidiary after the date of the indenture, or if any Restricted Subsidiary that is not already a Guarantor guarantees any other Indebtedness of the Company after such date, then in either case that Subsidiary will become a Guarantor by executing a supplemental indenture and delivering it to the trustee within 20 Business Days of the date on which it was acquired or created or guaranteed Indebtedness of the Company, as the case may be; provided, however, that the foregoing shall not apply to Subsidiaries of the Company that have properly been designated as Unrestricted Subsidiaries in accordance with the indenture for so long as they continue to constitute Unrestricted Subsidiaries.

Sale and Leaseback Transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, enter into any sale and leaseback transaction; provided that the Company or any Guarantor may enter into a sale and leaseback transaction if:

(1) the Company or that Guarantor, as applicable, could have (a) incurred Indebtedness in an amount equal to the Attributable Debt relating to such sale and leaseback transaction under the Fixed Charge Coverage Ratio test in the first paragraph of the covenant described above under the caption “ — Incurrence of Indebtedness and Issuance of Preferred Stock” and (b) incurred a Lien to secure such Indebtedness pursuant to the covenant described above under the caption “ — Liens;”

(2) the gross cash proceeds of that sale and leaseback transaction are at least equal to the fair market value, as determined in good faith by the Board of Directors and set forth in an officers’ certificate delivered to the trustee, of the property that is the subject of that sale and leaseback transaction; and

(3) the transfer of assets in that sale and leaseback transaction is permitted by, and the Company applies the proceeds of such transaction in compliance with, the covenant described above under the caption “ — Repurchase at the Option of Holders — Asset Sales.”

Business Activities

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business, except to such extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole, and Parent will not engage in any business other than the Permitted Parent Business, except to such extent as would not be material to Parent.

Reports

Whether or not required by the Commission, so long as any notes are outstanding, the Parent will file with the Commission for public availability within the time periods specified in the Commission’s rules and regulations (unless the Commission will not accept such a filing), and the Parent will furnish to the trustee and, upon its request, to any of the Holders of notes, within five Business Days of filing, or attempting to file, the same with the Commission:

(1) all quarterly and annual financial and other information with respect to the Parent and its Subsidiaries that would be required to be contained in a filing with the Commission on Forms 10-Q and 10-K if the Parent were required to file such Forms, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to the annual information only, a report on the annual financial statements by the Parent’s certified independent accountants;

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(2) all current reports that would be required to be filed with the Commission on Form 8-K if the Parent were required to file such reports; and

(3) unaudited quarterly and audited annual financial statements of the Company and its Subsidiaries.

Notwithstanding any of the foregoing, if the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the Company’s quarterly and annual financial information required by the preceding paragraph will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

In addition, the Company and the Guarantors have agreed that, for so long as any notes remain outstanding, they will furnish to the Holders and to securities analysts and prospective investors in the notes, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Events of Default and Remedies

Each of the following is an Event of Default:

(1) default for 30 days in the payment when due of interest, on the notes;

(2) default in payment when due of the principal of, or premium, if any, on the notes;

(3) failure by the Company to comply with the provisions described under “ — Certain Covenants — Merger, Consolidation or Sale of Assets” or under the captions “ — Repurchase at the Option of Holders — Asset Sales” or “ — Repurchase at the Option of Holders — Change of Control”;

(4) failure by the Parent, the Company or any of its Restricted Subsidiaries, as applicable, to comply for 30 days after receipt of written notice from the Trustee or the Holders of 25% in principal amount of the notes with the provisions described under the captions “ — Certain Covenants — Restricted Payments,” “ — Incurrence of Indebtedness and Issuance of Preferred Stock,” “ — Liens,” “ — Dividends and Other Payment Restrictions Affecting Subsidiaries,” “ — Transactions with Affiliates,” “ — Additional Guarantees,” “ — Sale and Leaseback Transactions,” and “ — Business Activities”;

(5) failure by the Company or the Parent, as applicable, for 60 days after notice from the trustee or the Holders of 25% of the principal amount of the notes outstanding to comply with any of the other agreements in the indenture (or 120 days with respect to the covenant described above under “Reports,” provided, however, that beginning on the 61^st day the Company is not in compliance with the covenant under “Reports,” additional interest at a rate of 0.25% per annum shall accrue and be payable on the notes until such covenant is complied with);

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), whether such Indebtedness or guarantee now exists, or is created after the date of the indenture, if that default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (a “Payment Default”); or

(b) results in the acceleration of such Indebtedness prior to its Stated Maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $15 million or more;

(7) failure by the Company or any of its Restricted Subsidiaries to pay final judgments aggregating in excess of $15 million, which judgments are not paid, discharged or stayed (including a stay pending

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appeal) for a period of 60 days after the date of such final judgment (or, if later, the date when payment is due pursuant to such judgment);

(8) except as permitted by the indenture, any Guarantee shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any Guarantor, or any Person acting on behalf of any Guarantor, shall deny or disaffirm its obligations under its Guarantee; and

(9) certain events of bankruptcy, insolvency or reorganization described in the indenture with respect to the Company or any of its Significant Subsidiaries or any group of Subsidiaries of the Company that, taken as a whole, would constitute a Significant Subsidiary.

In the case of an Event of Default arising from certain events of bankruptcy, insolvency or reorganization, with respect to the Company, any Subsidiary of the Company that is a Significant Subsidiary or any group of Subsidiaries of the Company that, taken together, would constitute a Significant Subsidiary, all outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the Holders of at least 25% in principal amount of the then outstanding notes may declare all the notes to be due and payable immediately.

Holders of the notes may not enforce the indenture or the notes except as provided in the indenture. Subject to certain limitations, Holders of a majority in principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold notice of any continuing Default or Event of Default from Holders of the notes if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal of, or interest or premium, if any, on, the notes.

The Holders of a majority in principal amount of the notes then outstanding by notice to the trustee may on behalf of the Holders of all of the notes waive any past Default or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of principal of, or interest or premium, if any, on the notes or in respect of a covenant that cannot be amended without the consent of each Holder.

In the case of any Event of Default occurring by reason of any willful action or inaction taken or not taken by or on behalf of the Company with the intention of avoiding payment of the premium that the Company would have had to pay if the Company then had elected to redeem the notes prior to stated maturity (other than with the net cash proceeds of an Equity Offering), an equivalent premium will also become and be immediately due and payable to the extent permitted by law upon the acceleration of the notes.

The Company is required to deliver to the trustee annually a statement regarding compliance with the indenture. Upon becoming aware of any Default or Event of Default, the Company is required to deliver to the trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder or other owner of Capital Stock of the Company or any Guarantor, as such, will have any liability for any obligations of the Company or any Guarantor under the notes, the indenture or the Guarantees, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Legal Defeasance and Covenant Defeasance

The Company may at its option and, at any time, elect to have all of its obligations discharged with respect to outstanding notes and all obligations of the Guarantors discharged with respect to their Guarantees (“Legal Defeasance”) except for:

(1) the rights of Holders of outstanding notes to receive payments in respect of the principal of, and interest or premium, if any, on such notes when such payments are due from the trust referred to below;

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(2) the Company’s obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the trustee, and the Company’s obligations in connection therewith; and

(4) the Legal Defeasance provisions of the indenture.

In addition, the Company may, at its option and at any time, elect to have its obligations released with respect to certain covenants that are described in the indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, insolvency or reorganization events) described under “ — Events of Default and Remedies” will no longer constitute an Event of Default with respect to the notes. If the Company exercises either its Legal Defeasance or Covenant Defeasance option, each Guarantor will be released and relieved of any obligations under its Guarantee and any security for the notes (other than the trust) will be released.

In order to exercise either Legal Defeasance or Covenant Defeasance:

(1) the Company must irrevocably deposit with the trustee, in trust, for the benefit of the Holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, and interest and premium, if any, on the outstanding notes on the date of fixed maturity or on the applicable redemption date, as the case may be, and the Company must specify whether the notes are being defeased to the date of fixed maturity or to a particular redemption date;

(2) in the case of Legal Defeasance, the Company has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that:

(a) the Company has received from, or there has been published by, the Internal Revenue Service a ruling; or

(b) since the date of the indenture, there has been a change in the applicable federal income tax law,

in either case to the effect that, and based thereon such opinion of counsel will confirm that, the Holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Company has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the Holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit);

(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which the Company or any of the Guarantors (other than Parent) is a party or by which the Company or any of the Guarantors (other than Parent) is bound;

(6) the Company must have delivered to the trustee an opinion of counsel to the effect that after the 91st day following the deposit (or, if any Holder or Beneficial Owner of notes is an insider of the

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Company, such later date as counsel may specify in such opinion), the trust funds will not be subject to the effect of Section 547 of the Federal Bankruptcy Code;

(7) the Company must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Company with the intent of preferring the Holders of notes over the other creditors of the Company with the intent of defeating, hindering, delaying or defrauding creditors of the Company or others; and

(8) the Company must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Amendment, Supplement and Waiver

Except as provided in the next three succeeding paragraphs, the indenture, the notes, or the Guarantees may be amended or supplemented with the consent of the Holders of at least a majority in principal amount of the notes affected thereby then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes), and any existing Default or Event of Default or compliance with any provision of the indenture, the notes or the Guarantees may be waived with the consent of the Holders of a majority in principal amount of the then outstanding notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

Without the consent of each Holder affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting Holder):

(1) reduce the principal amount of notes whose Holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any note or alter the provisions with respect to the redemption or repurchase of the notes (other than provisions relating to the covenants described above under the caption “ — Repurchase at the Option of Holders”);

(3) reduce the rate of or change the time for payment of interest, including any default interest, on any note;

(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, if any, on the notes (except a rescission of acceleration of the notes by the Holders of at least a majority in principal amount of the notes and a waiver of the payment default that resulted from such acceleration);

(5) make any note payable in currency other than that stated in the notes;

(6) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of Holders of notes to receive payments of principal of, or interest or premium, if any, on the notes (other than as permitted in clause (7) below);

(7) waive a redemption or repurchase payment with respect to any note (other than a payment required by one of the covenants described above under the caption “ — Repurchase at the Option of Holders”);

(8) release any Guarantor from any of its obligations under its Guarantee or the indenture, except in accordance with the terms of the indenture; or

(9) make any change in the preceding amendment, supplement and waiver provisions.

Notwithstanding the preceding, without the consent of any Holder of notes, the Company, the Guarantors and the trustee may amend or supplement the indenture, the notes, or the Guarantees:

(1) to cure any ambiguity, defect or inconsistency;

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

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(3) to provide for the assumption of the Company’s or a Guarantor’s obligations to Holders of notes in the case of a merger or consolidation or sale of all or substantially all of the Company’s or a Guarantor’s properties or assets;

(4) to make any change that would provide any additional rights or benefits to the Holders of notes or that does not adversely affect the legal rights under the indenture of any Holder, provided that any change to conform the indenture to this Memorandum will not be deemed to adversely affect the legal rights under the indenture of any holder;

(5) to secure the notes or the Guarantees pursuant to the requirements of the covenant described above under the subheading “ — Certain Covenants — Liens;”

(6) to provide for the issuance of additional notes in accordance with the limitations set forth in the indenture;

(7) to add any additional Guarantor or to evidence the release of any Guarantor from its Guarantee, in each case as provided in the indenture;

(8) to comply with requirements of the Commission in order to effect or maintain the qualification of the indenture under the Trust Indenture Act; or

(9) to evidence or provide for the acceptance of appointment under the indenture of a successor trustee.

Neither the Parent, the Company nor any of the Company’s Subsidiaries shall, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any Beneficial Owner or Holder of any notes for or as an inducement to any consent to any waiver, supplement or amendment of any terms or provisions of the indenture or the notes, unless such consideration is offered to be paid or agreed to be paid to all Beneficial Owners and Holders of the notes which so consent in the time frame set forth in solicitation documents relating to such consent.

Satisfaction and Discharge

The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise specified in the indenture), when:

(1) either:

(a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to the Company, have been delivered to the trustee for cancellation; or

(b) all notes that have not been delivered to the trustee for cancellation have become due and payable or will become due and payable within one year by reason of the mailing of a notice of redemption or otherwise and the Company or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the Holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the notes not delivered to the trustee for cancellation for principal, premium, if any, and accrued interest to the date of fixed maturity or redemption;

(2) no Default or Event of Default has occurred and is continuing on the date of the deposit or will occur as a result of the deposit and the deposit will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which the Company or any of Guarantors is a party or by which the Company or any Guarantor is bound;

(3) the Company or any Guarantor has paid or caused to be paid all sums payable by it under the indenture; and

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(4) the Company has delivered irrevocable instructions to the trustee under the indenture to apply the deposited money toward the payment of the notes at fixed maturity or the redemption date, as the case may be.

In addition, the Company must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Concerning the Trustee

If the trustee becomes a creditor of the Company or any Guarantor, the indenture limits its right to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Trust Indenture Act) after a Default has occurred and is continuing, it must eliminate such conflict within 90 days, apply to the Commission for permission to continue or resign.

The Holders of a majority in principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The indenture provides that in case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any Holder of notes, unless such Holder has offered to the trustee security or indemnity satisfactory to it against any loss, liability or expense.

Governing Law

The indenture, the notes and the Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Additional Information

Anyone who receives this Memorandum may obtain a copy of the indenture and registration rights agreement without charge by writing to the Company at 1021 Main, Suite 2626, Houston, Texas 77002, Attn: Chief Financial Officer.

Copies of the indenture relating to the notes and all agreements in connection with the issuance of the notes will also be available for inspection at the specified office of the paying agent in Luxembourg, if the notes are listed on the Luxembourg Stock Exchange and for so long as any notes are outstanding.

Registration Rights; Additional Interest

The Parent, the Company, the other Guarantors and the purchasers of the notes have entered into a registration rights agreement dated June 8, 2007. The following description is a summary of the material provisions of the registration rights agreement. It does not restate that agreement in its entirety. We urge you to read the proposed form of registration rights agreement in its entirety because it, and not this description, defines your registration rights as Holders of the notes. See “ — Additional Information.”

Pursuant to the registration rights agreement, the Company and the Guarantors agreed that they will, subject to certain exceptions,

(1) within 90 days after the date of original issue of the old notes (the “Issue Date”), file this registration statement (the “Exchange Offer Registration Statement”) with the SEC with respect to a Registered Exchange Offer to exchange the old notes for the new notes of the Company;

(2) use their reasonable best efforts to cause the Exchange Offer Registration Statement to be declared effective under the Securities Act within 270 days after the Issue Date;

(3) as soon as practicable after the effectiveness of the Exchange Offer Registration Statement (the “Effectiveness Date”), offer the Exchange Notes in exchange for the notes; and

(4) keep the Registered Exchange Offer open for not less than 30 days (or longer if required by applicable law) after the date notice of the Registered Exchange Offer is mailed to the Holders of the notes.

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In the event that:

(1) any change in law or in applicable interpretations thereof by the staff of the SEC does not permit us to effect the Registered Exchange Offer;

(2) for any other reason we do not consummate the Registered Exchange Offer within 310 days of the Issue Date;

(3) a purchaser notifies us following consummation of the Registered Exchange Offer that old notes held by it are not eligible to be exchanged for Exchange Notes in the Registered Exchange Offer; or

(4) certain Holders are prohibited by law or SEC policy from participating in the Registered Exchange Offer or may not resell the new notes acquired by them in the Registered Exchange Offer to the public without delivering a prospectus,

then, the Company and the Guarantors will, subject to certain exceptions,

(1) promptly file a shelf registration statement (the “Shelf Registration Statement”) with the SEC covering resales of the old notes or the new notes, but in no event later than the 30th day following notice of items (1) through (4) of the preceding paragraph;

(2) (A) in the case of clause (1) above, use their reasonable best efforts to cause the Shelf Registration Statement to be declared effective under the Securities Act on or prior to the 270th day after the Issue Date and (B) in the case of clause (2), (3) or (4) above, use their reasonable best efforts to cause the Shelf Registration Statement to be declared effective under the Securities Act on or prior to the 180th day after the date on which the Shelf Registration Statement is required to be filed; and

(3) use their reasonable best efforts to keep the Shelf Registration Statement effective until the earliest of (A) the time when the notes covered by the Shelf Registration Statement can be sold pursuant to Rule 144 without any limitations under clause (c), (e), (f) and (h) of Rule 144, (B) two years from the Issue Date and (C) the date on which all notes registered thereunder are disposed of in accordance therewith.

We will, in the event a Shelf Registration Statement is filed, among other things, provide to each Person for whom such Shelf Registration Statement was filed copies of the prospectus which is part of the Shelf Registration Statement, notify each such Person when the Shelf Registration Statement has become effective and take certain other actions as are required to permit unrestricted resales of the old notes or the new notes, as the case may be. A Person selling such old notes or new notes pursuant to the Shelf Registration Statement generally would be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such holder (including certain indemnification obligations).

We may require each Person requesting to be named as a selling security holder to furnish to us such information regarding the Person and the distribution of the old notes or new notes by the Person as we may from time to time reasonably require for the inclusion of the Person in the Shelf Registration Statement, including requiring the Person to properly complete and execute such selling security holder notice and questionnaires, and any amendments or supplements thereto, as we may reasonably deem necessary or appropriate. We may refuse to name any Person as a selling security holder that fails to provide us with such information.

If we are successful in listing the notes on the Luxembourg Stock Exchange, and for so long as the notes are listed on the official list of the Luxembourg Stock Exchange and the rules of the Luxembourg Stock Exchange so require, we and the Guarantors will inform the Luxembourg Stock Exchange, and publish a notice in a Luxembourg newspaper in the event, of any accrual of additional interest or any other change in the rate of interest payable on the notes, no later than the commencement of such accrual. In the event of a Registered Exchange Offer:

• we and the guarantors will make available the notices to the public in written form at places indicated by announcements to be published in a leading newspaper having a general circulation in Luxembourg (which is expected to be the d’Wort) or on the website of the Luxembourg Stock

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Exchange, www.bourse.lu, or by other means considered equivalent by the Luxembourg Stock Exchange, the announcement of the beginning of the Registered Exchange Offer and, following completion of such offer, the results of such offer;

• we and the guarantors will appoint a Luxembourg exchange agent through which all relevant documents with respect to the Registered Exchange Offer will be made available; and

• the registered Luxembourg exchange agent shall perform all agency functions to be performed by any exchange agent, including providing a letter of transmittal and other relevant documents to holders of notes, accepting such documents on our behalf, accepting definitive notes for exchange, and delivering exchange notes to holders of notes entitled thereto.

If we are successful in listing the notes on a European stock exchange other than the Luxembourg Stock Exchange, we shall also ensure that notices are duly published in a manner that complies with the rules and regulations of any other stock exchange and/or markets and/or alternative trading system or multilateral trading facility on which the notes are for the time being listed.

We will pay, as liquidated damages, additional cash interest on the applicable old notes or new notes, subject to certain exceptions,

(1) if the Company and the Guarantors fail to file an Exchange Offer Registration Statement with the SEC on or prior to the 90th day after the Issue Date,

(2) if the Exchange Offer Registration Statement is not declared effective by the SEC on or prior to the 270th day after the Issue Date or, if the Company and the Guarantors are obligated to file a Shelf Registration Statement pursuant to clause 2(A) above, a Shelf Registration Statement is not declared effective by the SEC on or prior to the 270th day after the Issue Date,

(3) if the Registered Exchange Offer is not consummated on or before the 40th day after the Effectiveness Date,

(4) if they are obligated to file the Shelf Registration Statement pursuant to clause 2(B) above, the Company and the Guarantors fail to file the Shelf Registration Statement with the SEC on or prior to the 90th day (the “Shelf Filing Date”) after the date on which the obligation to file a Shelf Registration Statement arises,

(5) if the Company and the Guarantors are obligated to file a Shelf Registration Statement pursuant to clause 2(B) above, the Shelf Registration Statement is not declared effective on or prior to the 90th day after the Shelf Filing Date, or

(6) after the Exchange Offer Registration Statement or the Shelf Registration Statement, as the case may be, is declared effective, such Registration Statement thereafter ceases to be effective or usable (subject to certain exceptions) (each such event referred to in this clause (6) and the preceding clauses (1) through (5) being called a “Registration Default”),

from and including the date on which any such Registration Default shall occur to but excluding the earlier to occur of (i) the date on which all Registration Defaults have been cured or (ii) the date on which all of the notes otherwise become freely tradeable by Holders, other than Affiliates of the Issuer, without further registration under the Securities Act.

The rate of the additional interest will be 0.25% per annum for the first 90-day period immediately following the occurrence of a Registration Default, and such rate will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all Registration Defaults have been cured, up to a maximum additional interest rate of 1.00% per annum. We will pay such additional interest on regular interest payment dates. Such additional interest will be in addition to any other interest payable from time to time with respect to the notes and the Exchange Notes.

We will be entitled to close the Registered Exchange Offer 30 days after it commences, provided that we have accepted all notes theretofore validly tendered in accordance with the terms of the Registered Exchange Offer.

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Certain Definitions

Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

“ACNTA” (Adjusted Consolidated Net Tangible Assets) means (without duplication), as of the date of determination:

(1) the sum of:

(a) discounted future net revenue from proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a reserve report prepared as of the end of the Company’s most recently completed fiscal year, which reserve report is prepared or reviewed or audited by an independent petroleum engineer as to reserves accounting for at least 80% of all such discounted future net revenue and by the Company’s petroleum engineers with respect to any other such reserves covered by such report, as increased by, as of the date of determination, the discounted future net revenue from:

(i) estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to acquisitions consummated since the date of such year-end reserve report, and

(ii) estimated crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward determinations of estimates of proved crude oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior year end) due to exploration, development or exploitation, production or other activities which reserves were not reflected in such year-end reserve report,

in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report), and decreased by, as of the date of determination, the discounted future net revenue attributable to

(iii) estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report produced or disposed of since the date of such year-end reserve report and

(iv) reductions in the estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report since the date of such year-end reserve report attributable to downward determinations of estimates of proved crude oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such year-end reserve report,

in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report); provided, however, that, in the case of each of the determinations made pursuant to clauses (i) through (iv), such increases and decreases shall be as estimated by the Company’s engineers, except that if as a result of such acquisitions, dispositions, discoveries, extensions or revisions, there is a Material Change, then such increases and decreases in the discounted future net revenue shall be confirmed in writing by an independent petroleum engineer;

(b) the capitalized costs that are attributable to crude oil and natural gas properties of the Company and its Restricted Subsidiaries to which no proved crude oil and natural gas reserves are attributed, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest annual or quarterly financial statements;

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(c) the Net Working Capital on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and

(d) the greater of (I) the net book value on a date no earlier than the date of the Company’s latest annual or quarterly financial statements and (II) the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries as of a date no earlier than the date of the Company’s latest audited financial statements;

(2) minus, to the extent not otherwise taken into account in the immediately preceding clause (1), the sum of:

(a) minority interests;

(b) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest audited financial statements;

(c) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report), attributable to reserves subject to participation interests, overriding royalty interests or other interests of third parties, pursuant to participation, partnership, vendor financing or other agreements then in effect, or which otherwise are required to be delivered to third parties;

(d) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto; and

(e) the discounted future net revenue, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production included in determining the discounted future net revenue specified in the immediately preceding clause (1)(a) (utilizing the same prices utilized in the Company’s year-end reserve report), would be necessary to satisfy fully the obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.

If the Company changes its method of accounting for its oil and gas properties from the full cost method to the successful efforts method or a similar method of accounting, ACNTA will continue to be calculated as if the Company were still using the full cost method of accounting.

For the avoidance of doubt, for purposes of this covenant, “the Company’s year-end end reserve report” shall mean (i) until such time as the Company’s reserve reports for the year ending June 30, 2007 have been prepared by the Company’s independent petroleum engineers, (a) the reserve report as of June 30, 2006 relating to the Marlin Assets prepared by Netherland Sewell & Associates, Inc. and the reserve report as of June 30, 2006 relating to the Castex Assets prepared by Miller and Lents, Ltd. and (b) the reserve report dated as of December 31, 2006 relating to the Pogo Assets prepared by Ryder Scott Company, LP, and (ii) following such time as the Company’s year-end reserve report or reports, as the case may be, for the year ending June 30, 2007 have been prepared by one or more of the Company’s independent petroleum engineers, the Company’s most recent reserve report or reports prepared by one or more of the Company’s independent petroleum engineers as of the last date of the Company’s most recent fiscal year.

“Acquired Debt” means, with respect to any specified Person:

(1) Indebtedness of any other Person existing at the time such other Person was merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Subsidiary of, such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

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“Additional Assets” means:

(1) any assets used or useful in the Oil and Gas Business;

(2) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or another Restricted Subsidiary; or

(3) Capital Stock constituting a minority in any Person that at such time is a Restricted Subsidiary;

provided, however, that any such Restricted Subsidiary described in clause (2) or (3) is primarily engaged in the Oil and Gas Business.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; provided that beneficial ownership of 10% or more of the Voting Stock of a Person will be deemed to be control. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings. For the avoidance of doubt, the Parent and any of its existing or future Subsidiaries, in addition to the Company and its Restricted Subsidiaries, will be considered Affiliates of the Company.

“Asset Sale” means:

(1) the sale, lease, conveyance or other disposition of any properties or assets (including by way of a Production Payment or sale and leaseback transaction); provided that the disposition of all or substantially all of the properties or assets of the Company and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the caption “ — Repurchase at the Option of Holders — Change of Control” and/or the provisions described above under the caption “ — Certain Covenants — Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant; and

(2) the issuance of Equity Interests in any of the Company’s Restricted Subsidiaries or the sale of Equity Interests in any of its Restricted Subsidiaries.

Notwithstanding the preceding, the following items will not be deemed to be Asset Sales:

(1) any single transaction or series of related transactions that involves properties or assets having a fair market value of less than $2.5 million;

(2) a transfer of assets between or among any of the Company and its Restricted Subsidiaries,

(3) an issuance or sale of Equity Interests by a Restricted Subsidiary to the Company or to another Restricted Subsidiary;

(4) the sale, lease or other disposition of hydrocarbons, equipment, inventory, accounts receivable or other properties or assets in the ordinary course of business, including, without limitation, any abandonment, farm-in, farm-out, lease or sublease of any oil and gas properties or the forfeiture or other disposition of such properties pursuant to standard form operating agreements, in each case in the ordinary course of business in a manner customary in the Oil and Gas Business;

(5) the sale or other disposition of cash or Cash Equivalents;

(6) a Restricted Payment that is permitted by the covenant described above under the caption “ — Certain Covenants — Restricted Payments” or a Permitted Investment;

(7) any trade or exchange by the Company or any Restricted Subsidiary of oil and gas properties or other properties or assets for oil and gas properties or other properties or assets owned or held by another Person, provided that the fair market value of the properties or assets traded or exchanged by the Company or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the fair market value of the properties or assets (together with any cash) to be received by the

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Company or such Restricted Subsidiary, and provided further that any net cash received must be applied in accordance with the provisions described above under the caption “ — Repurchase at the Option of Holders — Asset Sales;”

(8) the creation or perfection of a Lien (but not the sale or other disposition of the properties or assets subject to such Lien); and

(9) surrender or waiver of contract rights or the settlement, release or surrender of contract, tort or other claims of any kind.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

“Board of Directors” means:

(1) with respect to a corporation, the board of directors of the corporation;

(2) with respect to a partnership, the Board of Directors of the general partner of the partnership; and

(3) with respect to any other Person, the board or committee of such Person serving a similar function.

“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the applicable Person to have been duly adopted by the Board of Directors of such Person and to be in full force and effect on the date of such certification, and delivered to the trustee.

“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in Houston, Texas or in New York, New York are authorized or required by law to close.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet in accordance with GAAP.

“Capital Stock” means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

“Cash Equivalents” means:

(1) United States dollars;

(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than six months from the date of acquisition;

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(3) certificates of deposit and eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any lender party to the Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $250.0 million and a Thomson Bank Watch Rating of “B” or better;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

(5) commercial paper having the highest rating obtainable from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and in each case maturing within six months after the date of acquisition; and

(6) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition.

“Castex Assets” means the assets acquired by the Company pursuant to that certain Purchase and Sale Agreement, dated as of June 6, 2006, by and between the Company, as buyer, 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., as sellers, as amended by that certain First Amendment to Purchase and Sale Agreement dated as of July 5, 2006, as further amended by that certain Second Amendment to Purchase and Sale Agreement dated as of July 10, 2006, and as may be amended, supplemented, restated or otherwise modified from time to time.

“Change of Control” means the occurrence of any of the following:

(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets (including Capital Stock) of (a) the Parent and its Subsidiaries taken as a whole, (b) the Company or (c) the Company’s Restricted Subsidiaries taken as a whole, to any “person” (as that term is used in Section 13(d)(3) of the Exchange Act);

(2) the adoption of a plan relating to the liquidation or dissolution of the Parent or the Company;

(3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” or “group” (as that term is used in Section 13(d)(3) of the Exchange Act) becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Parent or the Company, measured by voting power rather than number of shares, other than beneficial ownership by the Parent or any Subsidiary thereof, directly or indirectly, of Voting Stock of the Company;

(4) the first day on which a majority of the members of the Board of Directors of the Parent or the Company are not Continuing Directors; or

(5) the Parent, the Company (or any parent thereof) consolidates with, or merges with or into, any Person, or any Person consolidates with, or merges with or into the Parent, the Company (or any parent thereof) in any such event pursuant to a transaction in which any of the outstanding Voting Stock of the Parent, the Company (or any parent thereof), as the case may be, is converted into or exchanged for cash, securities or other property, other than any such transaction where the Voting Stock of the Company (or any parent thereof) outstanding immediately prior to such transaction is converted into or exchanged for Voting Stock (other than Disqualified Stock) of the surviving or transferee Person constituting a majority of the outstanding shares of such Voting Stock of such surviving or transferee Person (or any parent thereof) immediately after giving effect to such issuance; provided, however, that the consolidation or merger of any Subsidiary of the Parent (other than the Company and its Subsidiaries) shall not constitute a Change of Control if the Voting Stock of the Company continues to be owned directly or indirectly (through one or more Subsidiaries) by the Parent.

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“Commission” or “SEC” means the Securities and Exchange Commission.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus:

(1) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus

(2) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued and whether or not capitalized (excluding any interest attributable to Dollar-Denominated Production Payments but including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to interest rate Hedging Obligations, to the extent that any such expense was deducted in computing such Consolidated Net Income; plus

(3) depreciation, depletion and amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), impairment, exploration expense, and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion and amortization, impairment and other non-cash expenses were deducted in computing such Consolidated Net Income; plus

(4) unrealized non-cash losses resulting from foreign currency balance sheet adjustments required by GAAP to the extent such losses were deducted in computing such Consolidated Net Income; minus

(5) non-cash items increasing such Consolidated Net Income for such period, other than items that were accrued in the ordinary course of business; minus (to the extent included in determining Consolidated Net Income):

(6) the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments, in each case, on a consolidated basis and determined in accordance with GAAP.

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:

(1) the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be excluded, except to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

(2) the Net Income of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, partners or members;

(3) the cumulative effect of a change in accounting principles will be excluded;

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(4) income resulting from transfers of assets (other than cash) between the Company or any of its Restricted Subsidiaries, on the one hand, and an Unrestricted Subsidiary, on the other hand, will be excluded;

(5) any write-downs of non-current assets will be excluded; provided that any ceiling limitation write-downs under Commission guidelines shall be treated as capitalized costs, as if such write-downs had not occurred;

(6) any unrealized non-cash gains or losses or charges in respect of hedge or non-hedge derivatives (including those resulting from the application of FAS 133) will be excluded;

(7) any non-cash compensation charge arising from any grant of stock, stock options or other equity-based awards will be excluded;

(8) any item classified as an extraordinary, unusual or nonrecurring gain, loss or charge will be excluded; and

(9) all deferred financing costs written off and premiums paid in connection with any early extinguishment of Indebtedness will be excluded; and

(10) all Permitted Payments to Parent will be excluded.

In addition, notwithstanding the preceding, for the purposes of the covenant described under “ — Certain Covenants — Restricted Payments” only, there shall be excluded from Consolidated Net Income any nonrecurring charges relating to any premium or penalty paid, write off of deferred finance costs or other charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Parent or the Company, as applicable, who:

(1) was a member of such Board of Directors on the date of the indenture; or

(2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election.

“Credit Agreement” means the Amended and Restated First Lien Credit Agreement to be entered into as of the Issue Date among Energy XXI Gulf Coast, Inc., as borrower, the various lenders named therein, The Royal Bank of Scotland plc, RBS Securities Corporation, BNP Paribas and Harris Nesbitt Financing. Inc., providing for revolving credit borrowings, including any related notes, guarantees, collateral documents, instruments and agreements executed in connection therewith, and in each case as amended, restated, modified, renewed, refunded, replaced or refinanced from time to time.

“Credit Facilities” means one or more debt facilities (including, without limitation, the Credit Agreement), commercial paper facilities or secured capital markets financings, in each case with banks or other institutional lenders or institutional investors providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from (or sell receivables to) such lenders against such receivables), letters of credit or secured capital markets financings, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced (including refinancing with any capital markets transaction) in whole or in part from time to time.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require the Company to repurchase or redeem such Capital Stock upon the occurrence

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of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that the Company may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “ — Certain Covenants — Restricted Payments.”

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary of the Company other than a Foreign Subsidiary.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means any public or private sale of Capital Stock (other than Disqualified Stock) made for cash on a primary basis by the Company after the date of the indenture.

“Existing Indebtedness” means the aggregate principal amount of Indebtedness of the Company and its Restricted Subsidiaries (other than Indebtedness under the Credit Agreement which is considered incurred under the first paragraph under the covenant entitled “Incurrence of Indebtedness and Issuance of Preferred Stock”) in existence on the date of the indenture, until such amounts are repaid.

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any four-quarter reference period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period provided, that, for purposes of calculating the Fixed Charge Coverage Ratio prior to the availability of financial statements for the quarter ended June 30, 2007, the Fixed Charge Coverage Ratio shall be calculated using Consolidated Cash Flow and Fixed Charges for the nine months ended March 31, 2007 multiplied by -4/3. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases or redeems any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the applicable four-quarter reference period and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, guarantee, repayment, repurchase or redemption of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom as if the same had occurred at the beginning of such period.

In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

(1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations and including any related financing transactions, subsequent to the commencement of the applicable four-quarter reference period and on or prior to the Calculation Date will be given pro forma effect as if they had occurred on the first day of such period, including any Consolidated Cash Flow, provided that any cost savings or operating improvements may be given such pro forma effect only if they are permitted by Regulation S-X promulgated under the Securities Act or any other regulation or policy of the Commission related thereto);

(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and assets, operations or businesses disposed of prior to the Calculation Date, will be excluded; and

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and assets, operations or businesses disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date.

“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:

(1) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued including, without limitation, amortization of debt issuance costs (excluding prepayment penalties associated with the repayment of debt from the proceeds of this offering) and

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original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to interest rate Hedging Obligations; plus

(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

(3) any interest expense on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such guarantee or Lien is called upon; plus

(4) the product of (a) all dividends, whether paid or accrued and whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of the Company (other than Disqualified Stock) or to the Company or a Restricted Subsidiary of the Company, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state and local statutory tax rate of such Person, expressed as a decimal,

in each case, on a consolidated basis and in accordance with GAAP.

“Foreign Subsidiary” means any Restricted Subsidiary of the Company that was not formed under the laws of the United States or any state of the United States or the District of Columbia and that conducts substantially all of its operations outside the United States.

“GAAP” means generally accepted accounting principles in the United States, which are in effect from time to time.

The term “guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness. When used as a verb, “guarantee” has a correlative meaning.

“Guarantee” means any guarantee by a Guarantor of the Company’s payment Obligations under the indenture and on the notes.

“Guarantors” means the Parent and each Restricted Subsidiary of the Company that executes the indenture as an initial Guarantor or that becomes a Guarantor in accordance with the provisions of the indenture, and their respective successors and assigns.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person incurred in the normal course of business and consistent with past practices and not for speculative purposes under:

(1) interest rate swap agreements, interest rate cap agreements and interest rate collar agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in interest rates with respect to Indebtedness incurred and not for purposes of speculation;

(2) foreign exchange contracts and currency protection agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in currency exchanges rates with respect to Indebtedness incurred and not for purposes of speculation;

(3) any commodity futures contract, commodity option or other similar agreement or arrangement designed to protect against fluctuations in the price of oil, natural gas or other commodities used, produced, processed or sold by that Person or any of its Restricted Subsidiaries at the time; and

(4) other agreements or arrangements designed to protect such Person or any of its Restricted Subsidiaries against fluctuations in interest rates, commodity prices or currency exchange rates.

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“Holder” means a Person in whose name a Note is registered.

“Indebtedness” means, with respect to any specified Person, without duplication,

(1) all obligations of such Person, whether or not contingent, in respect of:

(a) the principal of and premium, if any, in respect of outstanding (A) Indebtedness of such Person for money borrowed and (B) Indebtedness evidenced by notes, debentures, bonds or other similar instruments for the payment of which such Person is responsible or liable;

(b) all Capital Lease Obligations of such Person and all Attributable Debt in respect of sale and leaseback transactions entered into by such Person;

(c) the deferred purchase price of property, which purchase price is due more than six months after the date of taking delivery of title to such property, including all obligations of such Person for the deferred purchase price of property under any title retention agreement, but excluding accrued expenses and trade accounts payable arising in the ordinary course of business; and

(d) the reimbursement obligation of any obligor for the principal amount of any letter of credit, banker’s acceptance or similar transaction (excluding obligations with respect to letters of credit securing obligations (other than obligations described in clauses (a) through (c) above) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no later than the tenth Business Day following receipt by such Person of a demand for reimbursement following payment on the letter of credit);

(2) all net obligations in respect of Hedging Obligations except to the extent such net obligations are otherwise included in this definition;

(3) all liabilities of others of the kind described in the preceding clause (1) or (2) that such Person has Guaranteed or that are otherwise its legal liability;

(4) with respect to any Production Payment, any warranties or guaranties of production or payment by such Person with respect to such Production Payment but excluding other contractual obligations of such Person with respect to such Production Payment;

(5) Indebtedness (as otherwise defined in this definition) of another Person secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person, the amount of

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such obligations being deemed to be the lesser of

(a) the full amount of such obligations so secured, and

(b) the fair market value of such asset as determined in good faith by such specified Person;

(6) Disqualified Stock of such Person or a Restricted Subsidiary in an amount equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

(7) the aggregate preference in respect of amounts payable on the issued and outstanding shares of preferred stock of any of the Company’s Restricted Subsidiaries that are not Guarantors in the event of any voluntary or involuntary liquidation, dissolution or winding up (excluding any such preference attributable to such shares of preferred stock that are owned by such Person or any of its Restricted Subsidiaries; provided, that if such Person is the Company, such exclusion shall be for such preference attributable to such shares of preferred stock that are owned by the Company or any of its Restricted Subsidiaries); and

(8) any and all deferrals, renewals, extensions, refinancings and refundings (whether direct or indirect) of, or amendments, modifications or supplements to, any liability of the kind described in any of the preceding clauses (1), (2), (3), (4), (5), (6), (7) or this clause (8), whether or not between or among the same parties.

Subject to clause (4) of the preceding sentence, Production Payments shall not be deemed to be Indebtedness.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of the Company, the Company will be deemed to have made an Investment on the date of any such sale or disposition in an amount equal to the fair market value of the Equity Interests of such Restricted Subsidiary not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “ — Certain Covenants — Restricted Payments.”

“Issue Date” means the date on which notes are first issued under the indenture.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement not intended as a security agreement.

“Marlin Assets” means the assets acquired by the Company pursuant to that certain Purchase and Sale Agreement, dated as of February 21, 2006 by and between the Borrower and Marlin Energy, L.L.C., a Delaware limited liability company, as amended.

“Material Change” means an increase or decrease (excluding changes that result solely from changes in prices and changes resulting from the incurrence of previously estimated future development costs) of more than 25% during a fiscal quarter in the discounted future net revenues from proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries, calculated in accordance with clause (1)(a) of the definition of ACNTA; provided, however, that the following will be excluded from the calculation of Material Change:

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(1) any acquisitions during the fiscal quarter of oil and gas reserves that have been estimated by a nationally recognized firm of independent petroleum engineers and with respect to which a report or reports of such engineers exist; and

(2) any disposition of properties existing at the beginning of such fiscal quarter that have been disposed of in compliance with the covenant described under “ — Repurchase of the Option of Holders  — Assets Sales.”

“Material Domestic Subsidiary” means any Domestic Subsidiary that is not a Guarantor, when taken together with all other Domestic Subsidiaries that are not Guarantors, that at the time of determination has either assets or quarterly revenues in excess of 3.0% of the consolidated assets or quarterly revenues of the Company and its Restricted Subsidiaries, in each case based upon the most recent quarterly financial statements available to the Company.

“Net Income” means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however:

(1) any gain (but not loss), together with any related provision for taxes on such gain (but not loss), realized in connection with: (a) any Asset Sale; or (b) the disposition of any securities by such Person or any of its Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Subsidiaries; and

(2) any extraordinary gain (but not loss), together with any related provision for taxes on such extraordinary gain (but not loss).

“Net Proceeds” means the aggregate cash proceeds received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of, without duplication:

(1) the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale,

(2) taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements,

(3) amounts required to be applied to the repayment of Indebtedness, other than under the Credit Facilities, secured by a Lien on the properties or assets that were the subject of such Asset Sale, and

(4) any reserve for adjustment in respect of the sale price of such properties or assets established in accordance with GAAP.

“Net Working Capital” means:

(1) all current assets of the Company and its Restricted Subsidiaries, minus

(2) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness;

in each case, on a consolidated basis and determined in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness:

(1) as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) is the lender;

(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness (other than the notes) of the Company or any of

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its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity; and

(3) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of the Company or any of its Restricted Subsidiaries.

“Obligations” means any principal, premium, if any, interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization, whether or not a claim for post-filing interest is allowed in such proceeding), penalties, fees, charges, expenses, indemnifications, reimbursement obligations, damages, guarantees, and other liabilities or amounts payable under the documentation governing any Indebtedness or in respect thereto.

“Oil and Gas Business” means:

(1) the acquisition, exploration, development, operation and disposition of interests in oil, natural gas and other hydrocarbon properties;

(2) the gathering, marketing, treating, processing (but not refining), storage, selling and transporting of any production from those interests, including any hedging activities related thereto; and

(3) any activity necessary, appropriate, incidental or reasonably related to the activities described above.

“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business, including through agreements, transactions, interests or arrangements that permit one to share risk or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including without limitation:

(1) direct or indirect ownership of crude oil, natural gas, other related hydrocarbon and mineral properties or any interest therein or gathering, transportation, processing, storage or related systems; and

(2) the entry into operating agreements, joint ventures, processing agreements, working interests, royalty interests, mineral leases, farm-in agreements, farm-out agreements, development agreements, production sharing agreements, area of mutual interest agreements, contracts for the sale, transportation or exchange of crude oil and natural gas and related hydrocarbons and minerals, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, partnership agreements (whether general or limited), or other similar or customary agreements, transactions, properties, interests or arrangements and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding, however, Investments in corporations and publicly-traded limited partnerships.

“Permitted Investments” means:

(1) any Investment in the Company or in a Restricted Subsidiary of the Company;

(2) any Investment in Cash Equivalents;

(3) any Investment by the Company or any Restricted Subsidiary of the Company in a Person, if as a result of such Investment:

(a) such Person becomes a Restricted Subsidiary of the Company; or

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its properties or assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company;

(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “ — Repurchase at the Option of Holders — Asset Sales;”

(5) any Investment in any Person solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Company;

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(6) any Investments received in compromise of obligations of trade creditors or customers that were incurred in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer;

(7) Hedging Obligations permitted to be incurred under the “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant;

(8) Permitted Business Investments; and

(9) other Investments in any Person having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (9) that are at the time outstanding, not to exceed 2.0% of ACNTA.

“Permitted Parent Business” means:

(a) the ownership of all of the Capital Stock its existing Subsidiaries as of the Issue Date and any activities directly related to such ownership;

(b) the performance of its obligations under and in connection with its Guarantee of the Notes and any existing and future Credit Facilities and the performance of similar obligations with respect to any Credit Facilities or other items of Indebtedness of future direct subsidiaries of Parent, in each case otherwise permitted to be incurred under the covenant described above under the caption “ — Incurrence of Indebtedness and Issuance of Preferred Stock”;

(c) the undertaking of any actions required by law, regulation or order, including to maintain its existence;

(d) directly engaging in the Oil and Gas Business or the ownership of the Capital Stock of other Persons that are corporations or limited liability companies or other Persons consisting of limited partnership interests in limited partnerships, in each case, engaged in the Oil and Gas Business.

“Permitted Payments to Parent Companies” means:

(1) payments to the Parent or any of its Subsidiaries to permit them to pay their reasonable accounting, legal and administrative expenses when due, in an aggregate amount not to exceed $3.5 million per annum; and

(2) for so long as the Company is a member of a group filing a consolidated or combined tax return with Parent or any Subsidiary thereof, payments to Parent or any Subsidiary thereof in respect of an allocable portion of the tax liabilities of such group that is attributable to the Company and its Subsidiaries (“Tax Payments”); provided that the Tax Payments do not exceed the amount of the relevant tax (including any penalties and interest) that the Company would owe if the Company were filing a separate tax return (or a separate consolidated or combined return with its Subsidiaries that are members of the consolidated or combined group), taking into account any carryovers and carrybacks of tax attributes (such as net operating losses) of the Company and such Subsidiaries from other taxable years. Any Tax Payments received from the Company shall be paid over the appropriate taxing authority within 30 days of Parent’s receipt of such Tax Payments or refunded to the Company.

“Permitted Liens” means:

(1) Liens on any property or assets of the Company and any Guarantor securing Indebtedness and other obligations under Credit Facilities permitted under the indenture;

(2) Liens in favor of the Company or the Guarantors;

(3) Liens on any property or assets of a Person existing at the time such Person is merged with or into or consolidated with the Company or any Restricted Subsidiary of the Company, provided that such Liens were in existence prior to the contemplation of such merger or consolidation and do not

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extend to any property or assets other than those of the Person merged into or consolidated with the Company or the Restricted Subsidiary;

(4) Liens on any property or assets existing at the time of acquisition thereof by the Company or any Restricted Subsidiary of the Company, provided that such Liens were not incurred in connection with the contemplation of such acquisition;

(5) Liens to secure the performance of statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business;

(6) Liens existing on the Issue Date;

(7) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(8) Liens securing Permitted Refinancing Indebtedness incurred to refinance Indebtedness that was previously so secured, provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property that is the security for a Permitted Lien hereunder;

(9) Liens securing Hedging Obligations of the Company or any of its Restricted Subsidiaries;

(10) Liens securing Indebtedness incurred in connection with the acquisition by the Company or any Restricted Subsidiary of assets used in the Oil and Gas Business (including the office buildings and other real property used by the Company or such Restricted Subsidiary in conducting its operations); provided that (i) such Liens attach only to the assets acquired with the proceeds of such Indebtedness; (ii) such Indebtedness is not in excess of the purchase price of such fixed assets; and (iii) such Indebtedness is permitted to be incurred under the “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant;

(11) any Lien incurred in the ordinary course of business incidental to the conduct of the business of the Company or the Restricted Subsidiaries or the ownership of their property (including (a) easements, rights of way and similar encumbrances, (b) rights or title of lessors under leases (other than Capital Lease Obligations), (c) rights of collecting banks having rights of setoff, revocation, refund or chargeback with respect to money or instruments of the Company or the Restricted Subsidiaries on deposit with or in the possession of such banks, (d) Liens imposed by law, including Liens under workers’ compensation or similar legislation and mechanics’, carriers’, warehousemen’s, materialmen’s, suppliers’ and vendors’ Liens, and (e) Liens incurred to secure performance of obligations with respect to statutory or regulatory requirements, performance or return-of-money bonds, surety bonds or other obligations of a like nature and incurred in a manner consistent with industry practice;

(12) Liens for taxes, assessments and governmental charges not yet due or the validity of which are being contested in good faith by appropriate proceedings, promptly instituted and diligently conducted, and for which adequate reserves have been established to the extent required by GAAP as in effect at such time; and

(13) Liens incurred in the ordinary course of business of the Company or any Restricted Subsidiary of the Company with respect to obligations that do not exceed $10.0 million at any one time outstanding.

“Permitted Refinancing Indebtedness” means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:

(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness being

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extended, refinanced, renewed, replaced, defeased or refunded (plus all accrued interest on the Indebtedness and the amount of all expenses and premiums incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(3) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the notes or the Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to the notes or the Guarantees on terms at least as favorable to the Holders of notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and

(4) such Indebtedness is not incurred by a Restricted Subsidiary of the Company if the Company is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; provided, however, that a Restricted Subsidiary that is also a Guarantor may guarantee Permitted Refinancing Indebtedness incurred by the Company, whether or not such Restricted Subsidiary was an obligor or guarantor of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Pogo Assets” means the assets acquired by the Company pursuant to that certain Purchase and Sale Agreement, by and between Energy XXI GOM, LLC, as buyer, and Pogo Producing Company, as seller, as may be amended, supplemented, restated or otherwise modified from time to time.

“Production Payments” means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments.

“Registered Exchange Offer” has the meaning set forth for such term in the applicable registration rights agreement.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

“Senior Debt” means all Indebtedness of the Company or any of its Restricted Subsidiaries permitted to be incurred under the terms of the indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the notes or any Guarantee, and all Obligations with respect to the foregoing.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the indenture.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subsidiary” means, with respect to any specified Person:

(1) any corporation, association or other business entity (other than a partnership) of which more than 50% of the total voting power of Voting Stock is at the time owned or controlled, directly or through another Subsidiary, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

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(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof), or (c) as to which such Person and its Subsidiaries are entitled to receive more than 50% of the assets of such partnership upon its dissolution.

“Unrestricted Subsidiary” means any Subsidiary of the Company that is designated by the Board of Directors as an Unrestricted Subsidiary pursuant to a Board Resolution, but only to the extent that such Subsidiary:

(1) has no Indebtedness other than Non-Recourse Debt;

(2) is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary of the Company unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company;

(3) is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Company or any of its Restricted Subsidiaries.

Any designation of a Subsidiary of the Company as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee the Board Resolution giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “ — Certain Covenants — Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of the Company as of such date and, if such Indebtedness is not permitted to be incurred, and any Lien of such Subsidiary will be deemed to be incurred as of such date under the covenant, or such Lien is not permitted to be incurred as of such date under the covenant described under the caption “Liens”, then in, in either case, described under the caption “ — Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock,” the Company will be in default of such covenant.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all related undertakings and obligations.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

(2) the then outstanding principal amount of such Indebtedness.

Book-Entry, Delivery and Form

The notes are being offered and sold to investors, in the United States, to qualified institutional buyers or “QIBs” (as defined in Rule 144A of the Securities Act) (“QIB Notes”), and institutional “accredited investors”, or “IAIs” as defined in Regulation D of the Securities Act (the “IAI Notes”), and, outside the United States, to “non-U.S. Persons” or “non-U.S. Purchasers” (as defined in Regulation S of the Securities Act) in

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reliance on Regulation S of the Securities Act) (“Regulation S Notes”). Except as set forth below, notes will be issued in registered, global form in minimum denominations of $2,000 and integral multiples of $1,000 in excess of $1,000. Notes will be issued at the closing of this offering only against payment in immediately available funds.

QIB Notes initially will be represented by one or more notes in registered, global form without interest coupons (collectively, the “QIB Global Notes”). IAI Notes will initially be represented by one or more Global Notes in registered, global firm without interest coupons collectively. Regulation S Notes initially will be represented by one or more temporary notes in registered, global form without interest coupons (collectively, the “Regulation S Temporary Global Notes”). The QIB Global Notes, the IAI Notes and the Regulation S Temporary Global Notes will be deposited upon issuance with the trustee as custodian for The Depository Trust Company (“DTC”), in New York, New York, and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant in DTC as described below. Through and including the 40^th day after the later of the commencement of this offering and the closing of this offering (such period through and including such 40^th day, the “Restricted Period”), beneficial interests in the Regulation S Temporary Global Notes may be held only through the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”) (as indirect participants in DTC), unless transferred to a person that takes delivery through a QIB Global Note or IAI Note in accordance with the certification requirements described below. Within a reasonable time period after the expiration of the Restricted Period, the Regulation S Temporary Global Notes will be exchanged for one or more permanent notes in registered, global form without interest coupons (collectively, the “Regulation S Permanent Global Notes” and, together with the Regulation S Temporary Global Notes, the “Regulation S Global Notes;” the Regulation S Global Notes, the QIB Global Notes and IAI Note collectively being the “Global Notes”) upon delivery to DTC of certification of compliance with the transfer restrictions applicable to the notes and pursuant to Regulation S as provided in the indenture. Beneficial interests in the QIB Global Notes or IAI Notes may not be exchanged for beneficial interests in the Regulation S Global Notes at any time except in the limited circumstances described below. See “ — Exchanges between IAI Notes, Regulation S Notes and QIB Notes.”

Except as set forth below, the Global Notes may be transferred, in whole but not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for definitive notes in registered certificated form (“Certificated Notes”) notes except in the limited circumstances described below. See “ — Exchange of Global Notes for Certificated Notes.” Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of Certificated Notes.

QIB Notes and IAI Notes (including beneficial interests in the QIB Global Notes) and IAI Notes will be subject to certain restrictions on transfer and will bear a restrictive legend as described under “Notice to Investors.” Regulation S Notes will also bear a legend as described under “Notice to Investors.” In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depositary Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the banks), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are

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not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised us that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in the Global Notes).

Investors in the Global Notes who are Participants in DTC’s system may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants in such system. Investors in the Regulation S Global Notes must initially hold their interests therein through Euroclear or Clearstream, if they are participants in such systems, or indirectly through organizations that are participants. After expiration of the Restricted Period (but not earlier), investors may also hold their interests in the Regulation S Global Notes through Participants, other than Euroclear and Clearstream. Euroclear and Clearstream will hold interests in the Global Notes on behalf of their participants through customers’ securities accounts in their respective names on the books of their respective depositories, which are Euroclear Bank S.A./N.V., as operator of Euroclear, and Citibank, N.A., as operator of Clearstream. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems.

The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of an interest in the Global Notes will not have notes registered in their names, will not receive physical delivery of certificated notes and will not be considered the registered owners or “Holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest, premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered Holder under the indenture. Under the terms of the indenture, the Company and the trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Company, the trustee nor any agent of the Company or the trustee has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, at the due date of any payment in respect of securities such as the notes, is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants

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to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or the Company. Neither the Company nor the trustee will be liable for any delay by DTC or any of its Participants or Indirect Participants in identifying the beneficial owners of the notes, and the Company and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Subject to the transfer restrictions set forth under “Notice to Investors,” transfers between Participants will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Subject to compliance with the transfer restrictions applicable to the notes described herein, cross-market transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a Holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for legended notes in registered certificated form, and to distribute such notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the QIB Global Notes and the Regulation S Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. None of the Company, the trustee or any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes, if:

(1) DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and in either event the Company fails to appoint a successor depositary within 90 days; or

(2) there has occurred and is continuing an Event of Default and DTC notifies the trustee of its decision to exchange the Global Note for certificated notes.

Beneficial interests in a Global Note also may be exchanged for Certificated Notes upon prior written notice given to the trustee by or on behalf of DTC in the limited other circumstances permitted by the indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the restrictive legend referred to in “Notice to Investors,” unless that legend is not required by applicable law.

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Exchange of Certificated Notes for Global Notes

Certificated Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such notes. See “Notice to Investors.”

Exchanges Between IAI Notes, Regulation S Notes and QIB Notes

During the Restricted Period, a beneficial interest in a IAI Note or Regulation S Global Note may be transferred to a Person who takes delivery in the form of an interest in a QIB Global Note only if such exchange occurs in connection with a transfer of the notes pursuant to Rule 144A or another applicable exemption from the registration requirements of the Securities Act and the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that such transfer is being made to a Person who the transferor reasonably believes is purchasing for its own account or accounts as to which it exercises sole investment discretion and that such person is a QIB, in each case in a transaction meeting the requirements of Rule 144A and in accordance with any applicable securities laws of any state of the United States or any other jurisdiction. After the expiration of the Restricted Period, such certification requirements will not apply to such transfers of beneficial interests in the Regulation S Global Notes.

Beneficial interests in a QIB Global Note or IAI Note may be transferred to a Person who takes delivery in the form of an interest in a Regulation S Global Note, whether before or after the expiration of the Restricted Period, only if the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that such transfer is being made in accordance with Rule 903 or 904 of Regulation S or Rule 144 (if available).

Transfers involving exchanges of beneficial interests between the Regulation S Global Notes and the QIB Global Notes will be effected in DTC by means of an instruction originated by the trustee through the DTC Deposit/Withdraw at Custodian system. Accordingly, in connection with any such transfer, appropriate adjustments will be made to reflect a decrease in the principal amount of a Regulation S Global Note and a corresponding increase in the principal amount of a QIB Global Note or vice versa, as applicable. Any beneficial interest in one of the Global Notes that is transferred to a Person who takes delivery in the form of an interest in another Global Note will, upon transfer, cease to be an interest in such Global Note and will become an interest in the other Global Note and, accordingly, will thereafter be subject to all transfer restrictions and other procedures applicable to beneficial interest in such other Global Note for so long as it remains such an interest. The policies and practices of DTC may prohibit transfers of beneficial interests in the Regulation S Global Note prior to the expiration of the Restricted Period.

Same Day Settlement and Payment

The Company will make payments in respect of the notes represented by the Global Notes (including principal, interest and premium, if any) by wire transfer of immediately available funds to the accounts specified by the Global Note Holder. The Company will make all payments of principal, interest and premium, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the Holders of the Certificated Notes or, if no such account is specified, by mailing a check to each such Holder’s registered address. The notes represented by the Global Notes are expected to be eligible to trade in the PORTAL market and to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. The Company expects that secondary trading in any certificated notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant in DTC will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised us that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of certain federal income tax consequences relevant to the exchange of new notes for old notes, but does not purport to be a complete analysis for all potential tax effects. The summary is based upon the Internal Revenue Code of 1986, as amended, Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. The description does not consider the effect of any applicable foreign, state, local or other tax laws or estate or gift tax considerations. Each holder is encouraged to consult, and depend on, his own tax advisor in analyzing the particular tax consequences of exchanging such holder’s old notes for new notes, including the applicability and effect of any federal, state, local and foreign tax laws.

The exchange of new notes for old notes will not be a taxable event to a holder for United States federal income tax purposes. Accordingly, a holder will have the same adjusted issue price, adjusted basis and holding period in the new notes as it had in the old notes immediately before the exchange.

PLAN OF DISTRIBUTION

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for 180 days after the consummation of the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until             , 2007, all dealers effecting transactions in the new notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of new notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The enclosed letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 180 days after the consummation of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

LEGAL MATTERS

Certain legal matters in connection with the securities offered by this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas, and Appleby Hunter Bailhache.

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INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

The consolidated balance sheet of Energy XXI Gulf Coast, Inc. as of June 30, 2006 and the related consolidated statements of income, stockholders’ equity, and cash flows for the period from inception (February 7, 2006) through June 30, 2006, 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 Statement 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.

INDEPENDENT PETROLEUM ENGINEERS

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 the December 31, 2006 report of 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-4 with respect to the notes being offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the notes offered by this prospectus, please review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of this material can also be obtained from the public reference section of the SEC at prescribed rates, or accessed at the SEC’s website at www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room. In addition, our Parent files with or furnishes to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above.

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INDEX TO FINANCIAL STATEMENTS

Contents	Page
Energy XXI Gulf Coast, Inc. Consolidated Financial Statements (June 30, 2006)		F-2
Energy XXI Gulf Coast, Inc. Consolidated Financial Statements (March 31, 2007)		F-24
Energy XXI (Bermuda) Limited Consolidated Financial Statements (June 30, 2006)		F-33
Energy XXI (Bermuda) Limited Consolidated Financial Statements (March 31, 2007)		F-57
Energy XXI (Bermuda) Limited Carve-Out Financial Statements for Castex		F-73
Marlin Energy Offshore L.L.C., Marlin Texas GP, L.L.C. and Marlin Texas, L.P. Combined Financial Statements		F-79
Carve-Out Financial Statements for the Pogo Properties		F-92
Energy XXI (Bermuda) Limited Pro Forma Financial Statements		F-99

F-1

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder
Energy XXI Gulf Coast, Inc.

We have audited the accompanying consolidated balance sheet of Energy XXI Gulf Coast, Inc. (a Delaware 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 (February 7, 2006) 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 consolidated financial position of Energy XXI Gulf Coast, Inc. and subsidiaries as of June 30, 2006, and the consolidated results of their operations and their cash flows for the period from inception (February 7, 2006) 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 GULF COAST, INC.
  
CONSOLIDATED BALANCE SHEET
June 30, 2006
(In thousands, except share information)

ASSETS
Current assets:
Cash and cash equivalents	$	4,144
Receivables:
Oil and natural gas sales		19,325
Joint interest billings		11,173
Acquisition		14,070
Insurance		39,801
Prepaid expenses and other current assets		9,131
Royalty deposit		2,175
Derivative financial instruments		7,752
TOTAL CURRENT ASSETS		107,571
Oil and gas properties — full cost method of accounting, including $50,840 of unproved oil and gas properties as of June 30, 2006, net of accumulated depreciation, depletion, and amortization		447,852
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 ..	$	576,762
LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts payable	$	22,641
Advances from joint interest partners		6,211
Undistributed oil and natural gas proceeds		5,617
Affiliates’ payable		13,982
Accrued liabilities		5,693
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		65,732
Long-term debt, less current maturities		199,644
Asset retirement obligations		37,844
Derivative financial instruments		590
TOTAL LIABILITIES		303,810
COMMITMENTS AND CONTINGENCIES (NOTE 10)
STOCKHOLDERS EQUITY
Common stock, $0.01 par value, 1,000,000 shares authorized and 100,000 issued at June 30, 2006		1
Additional paid-in capital		274,492
Retained earnings		3,011
Accumulated other comprehensive loss, net of tax benefit		(4,552	)
TOTAL STOCKHOLDER'S EQUITY		272,952
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	576,762

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

F-4

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED STATEMENT OF INCOME
Inception (February 7, 2006) Through June 30, 2006
(In thousands)

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		20,225
Accretion of asset retirement obligation		738
General and administrative expense		3,485
Loss on derivative financial instruments		68
TOTAL COSTS AND EXPENSES		34,502
OPERATING INCOME		12,610
OTHER INCOME (EXPENSE)
Interest income		55
Interest expense		(7,927	)
INCOME BEFORE PROVISION FOR INCOME TAXES		4,738
PROVISION FOR INCOME TAXES		1,727
NET INCOME	$	3,011

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

F-5

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
Inception (February 7, 2006) Through June 30, 2006
(In thousands, except share information)

					Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Common Stock
	Shares		Amount
Issuance of common stock inception (February 7, 2006)		100,000	$	1	$	274,492	$	—	$	—		$	274,493
Comprehensive loss:
Net income		—		—		—		3,011		—			3,011
Unrealized loss on derivative financial instruments, net of tax		—		—		—		—		(4,552	)		(4,552	)
Total comprehensive loss													(1,541	)
Balance as of June 30, 2006		100,000	$	1	$	274,492	$	3,011		(4,552	)	$	272,952

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

F-6

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED STATEMENT OF CASH FLOWS
Inception (February 7, 2006) Through June 30, 2006
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	3,011
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.		20,225
Amortization of debt issuance costs		306
Changes in operating assets and liabilities:
Increases in receivables		(26,912	)
Increases in prepaid expenses and other current assets		(5,746	)
Increases in accounts payable and other liabilities		12,863
Increases in affiliates’ payable		2,283
NET CASH PROVIDED BY OPERATING ACTIVITIES		8,735
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition		(448,374	)
Capital expenditures, net of insurance reimbursements		(17,402	)
Purchase of derivative instruments		(3,168	)
Escrow deposit and acquisition costs		(10,025	)
NET CASH USED IN INVESTING ACTIVITIES		(478,969	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of common stock		274,493
Proceeds from Inter-company Loan		14,150
Payment on Inter-company Loan		(14,150	)
Proceeds from first lien revolver		117,500
Proceeds from second lien facility		75,000
Advances from affiliates		11,699
Debt issuance costs		(3,984	)
Payments on put financing		(330	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		474,378
NET INCREASE IN CASH AND CASH EQUIVALENTS		4,144
CASH AND CASH EQUIVALENTS, beginning of period		—
CASH AND CASH EQUIVALENTS, end of period	$	4,144

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

F-7

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 1 — Organization and Summary of Significant Accounting Policies

Energy XXI Gulf Coast, Inc. (“Energy XXI”), a Delaware corporation, was incorporated on February 7, 2006. Energy XXI (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company, 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 February 21, 2006, Energy XXI 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’s sole shareholder, Energy XXI USA. Inc. (the “Parent”) was assigned interest in a note purchase agreement entered into by Energy XXI (US Holdings) Limited (“US Holdings”), the sole shareholder of the Parent. In the note purchase agreement with Satellite Senior Income Fund, LLC (“Satellite”), US Holdings agreed to sell $17.5 million aggregate principal amount of Satellite’s 6.5% senior notes due May 11, 2006 for a price of $14.15 million. The Parent advanced the Company an amount equal to the note purchase agreement, with an interest rate equal to that in the note purchase agreement (the “Inter-company Loan”). 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, and used approximately $4 million to purchase crude oil put derivative instruments to partially hedge the acquisition’s cash flows. 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).

On April 4, 2006, the acquisition was funded with an equity contribution from the Parent of $274.5 million and commitments from The Royal Bank of Scotland and BNP Paribas for $375 million of financing facilities of which $220 million was available at closing.

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.

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

F-8

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

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 gas natural 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 (February 7, 2006) through June 30, 2006 of approximately $1.9 million.

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

F-9

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

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 (February 7, 2006) 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

F-10

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

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.

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 Instrument 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.

F-11

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

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. The adoption of SAB 108 is not expected to 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.

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

F-12

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 3 — Acquisition

On April 4, 2006, the Company completed the acquisition of the Oil and Gas Assets. 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. 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.

Note 4 — Long-Term Debt

First Lien Revolver: Energy XXI 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 13 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 Energy XXI. The first lien revolver is subject to early redetermi-nations, 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, Energy XXI 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.

F-13

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 4 — Long-Term Debt  – (continued)

Second Lien Facility: Energy XXI 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 Energy XXI. 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, Energy XXI 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 13, 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.

Inter-company Loan: The Company entered into the Inter-company Loan with the Parent on March 2, 2006, for $14.15 million. The Inter-company Loan was paid in full on April 4, 2006, including interest expense of $3.6 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 (February 7, 2006) 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		72,772
2011		—
Thereafter		—
Total		209,228
Less current portion		(9,584	)
Long-term debt	$	199,644

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 inception (February 7, 2006)	$	—
ARO acquired		36,595
Accretion expense		738
ARO incurred due to drilling activities		511
Carrying amount of ARO at June 30, 2006	$	37,844

F-14

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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 (February 7, 2006) 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 (February 7, 2006) 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 (February 7, 2006) through June 30, 2006.

As of June 30, 2006, the Company had the following hedge contracts outstanding:

	Crude Oil						Natural Gas							Total
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
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

F-15

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 6 — Derivative Financial Instruments  – (continued)

(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 (February 7, 2006) 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 (February 7, 2006) through June 30, 2006 (in thousands):

Accumulated other comprehensive income (loss) — inception (February 7, 2006)	$	—
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

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

Income before income taxes	$	4,738
Statutory rate		35	%
Income tax expense computed at statutory rate		1,658
Reconciling items:
State income taxes, net of federal tax benefit		50
Other		19
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):

F-16

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 7 — Income Taxes  – (continued)

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 — 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
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

Note 9 — Related Party Transactions

The Company has no employees; instead it receives management services from Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company. Other services provided by Energy Services include legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services. Cost of these services from inception (February 7, 2006) through June 30, 2006 was approximately $2.3 million, and is included in general and administrative expense and in affiliate’s payable, in the accompanying consolidated statement of income and consolidated balance sheet, respectively. As of June 30, 2006, approximately $11.7 million included in due to affiliates represents short-term working capital advances from the Parent and other affiliates.

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.

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.

F-17

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 10 — Commitments and Contingencies  – (continued)

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 11 — 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 (February 7, 2006) 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.

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. We believe that our credit risk related to the futures and swap contracts is no greater than the risk associated with the primary contracts and that the elimination of price risk through our hedging activities reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk.

Cash and Cash Equivalents: 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 12 — 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 13  —  Condensed Consolidating Financial Statements

The following unaudited condensed consolidating financial statements are presented pursuant to Rule 3-10 of Regulation S-X. Energy XXI is an issuer (the ``Subsidiary Issuer'') of 10% senior notes that are fully and unconditionally guaranteed by its parent, Energy XXI (Bermuda) Limited as well as each of its subsidiaries, Energy XXI Texas, LP, Energy XXI Texas GP, LLC and Energy XXI GOM, LLC (collectively, the “Subsidiary Guarantors”). Energy XXI and the Subsidiary Guarantors are 100% owned by Energy XXI (Bermuda) Limited.

F-18

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 13  —  Condensed Consolidating Financial Statements – (continued)

The indenture covering the senior notes limits EXXI and the Subsidiary Guarantors ability to transfer or sell assets, make investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of substantially all of their assets, enter into transactions with affiliates or engage in businesses other than the oil and gas business (in thousands).

	Parent		Subsidiary Issuer		Subsidiary Guarantors			Other Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	54,316	$	2,619	$	1,526		$	3,928	$	—		$	62,389
Receivables:		—		—		—			—		—			—
Oil and gas sales		—		—		19,325			—		—			19,325
Joint interest billing		—		—		11,173			—		—			11,173
Due from Seller		—		14,070		—			—		—			14,070
Stock Receivable		7,326		—		—			—		—			7,326
Insurance Receivable		—		—		39,801			—		—			39,801
Intercompany		10,519		421,878		(435,860	)		3,463		—			—
Prepaid expenses and other assets		30		7,790		1,341			39		—			9,200
Royalty deposit		—		—		2,175			—		—			2,175
Derivative instruments		—		7,752		—			—		—			7,752
Total current assets		72,191		454,109		(360,519	)		7,430					173,211
Property and equipment, net of depreciation, depletion, and amortization
Oil and gas properties — full cost method of accounting		—		—		447,852			—		—			447,852
Other property and equipment		—		—		—			1,569		—			1,569
Total property and equipment		—		—		447,852			1,569					449,421
Castex acquisition deposit		—		10,025		—			—		—			10,025
Derivative instruments		—		5,856		—			—		—			5,856
Deferred taxes		—		5,978		—			—		(4,198	)		1,780
Other assets		282,611		3,678		—			378,593		(661,204	)		3,678
TOTAL ASSETS	$	354,802	$	479,646	$	87,333		$	387,592	$	(665,402	)	$	643,971
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	95	$	22,546		$	640	$	—		$	23,281
Amounts due joint interest owners		—		—		6,211			—		—			6,211
Undistributed oil and gas proceeds		—		—		5,617			—		—			5,617
Accrued liabilities		59		2,574		3,120			93		—			5,846
Income and franchise taxes payable		—		913		—			—		—			913
Deferred income taxes		—		143		—			—		—			143
Derivative instruments		—		948		—			—		—			948
Current maturities of long-term debt		—		9,584		—			—		—			9,584
Total current liabilities		59		14,257		37,494			733					52,543
Long-term debt		—		199,644		—			—		—			199,644
Deferred taxes		—		—		4,198			—		(4,198	)		—
Asset retirement obligations		—		—		37,844			—		—			37,844

F-19

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 13  —  Condensed Consolidating Financial Statements – (continued)

	Parent		Subsidiary Issuer			Subsidiary Guarantors		Other Subsidiaries			Eliminations			Consolidated
Derivative liabilities		—		590			—		—			—			590
Other liabilities		—		—			—		641			—			641
Total liabilities		59		214,491			79,536		1,374			(4,198	)		291,262
Committment and Contingencies
Stockholders’ equity:
Preferred Stock, $.01 par value, 2,500,000 shares authorized, and no shares issued at June 30, 2006
Common stock, $.001 par value, 400,000,000 shares authorized, 80,645,129 issued at June 30, 2006		81		—			—		—			—			81
Additional paid-in capital		350,238		274,493			—		386,711			(661,204	)		350,238
Retained earnings		4,424		(4,786	)		7,797		(493	)		—			6,942
Other comprehensive income, net of tax		—		(4,552	)		—		—			—			(4,552	)
Total stockholders’ equity		354,743		265,155			7,797		386,218			(661,204	)		352,709
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	354,802	$	479,646		$	87,333	$	387,592		$	(665,402	)	$	643,971

F-20

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 13  —  Condensed Consolidating Financial Statements – (continued)

	Parent			Subsidiary Issuer			Subsidiary Guarantors		Other Subsidiaries			Consolidated
Revenues
Oil sales	$	—		$	(695	)	$	29,751	$	—		$	29,056
Gas sales		—			2,122			15,934		—			18,056
Total revenues		—			1,427			45,685		—			47,112
Operating Expense:
Lease operating expenses		—			—			9,902		—			9,902
Production taxes and transportation		—			—			84		—			84
Depreciation, depletion and amortization		—			—			20,225		132			20,357
General and administrative		515			696			2,789		361			4,361
Accretion of asset retirement obligation		—			—			738		—			738
Derivative loss		—			68			—		—			68
Total operating expenses		515			764			33,738		493			35,510
Income (loss) from operations		(515	)		663			11,947		(493	)		11,602
Other income (expenses):
Interest income		4,939			7			48		6			5,000
Interest expense		—			(7,927	)		—		(6	)		(7,933	)
Net income (loss) before income taxes		4,424			(7,257	)		11,995		(493	)		8,669
Provision for income taxes		—			(2,471	)		4,198		—			1,727
Net income (loss)		4,424			(4,786	)		7,797		(493	)		6,942

F-21

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 13  —  Condensed Consolidating Financial Statements – (continued)

	Parent			Subsidiary Issuer			Subsidiary Guarantors			Other Subsidiaries			Consolidated
Operating Activities:
Net Income (loss)		4,424			(4,786	)		7,797			(493	)		6,942
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income tax		—			(3,384	)		4,198			—			814
Unrealized loss on derivative instrument		—			(119	)		—			—			(119	)
Accrued interest classified with put premuum financing		—			100			—			—			100
Put premuim amortization		—			1,172			—			—			1,172
Accretion expense related to asset retirement obigations		—			—			738			—			738
Depletion, depreciation, and amortiztion		—			—			20,225			132			20,357
Amortization of debt issuance costs		188			306			—			—			494
Changes in operating assets and liabilities:
Accounts receivable (including intercompany)		—			—			(26,912	)		—			(26,912	)
Intercompany		(293,319	)		(164,653	)		453,317			4,655			—
Prepaid expenses and other current assets		(30	)		(4,405	)		(1,341	)		(39	)		(5,815	)
Accounts payable		60			3,583			9,280			1,374			14,297
Net cash provided by (used in) operating activities		(288,677	)		(172,186	)		467,302			5,629			12,068
Investing Activities:
Business acquired		—			—			(448,374	)		—			(448,374	)
Purchases of property and equipment		—			—			(27,725	)		(1,701	)		(29,426	)
Insurance Payments Received		—			—			10,323			—			10,323
Purchase of derivative instruments		—			(3,168	)		—			—			(3,168	)
Earnest deposit		—			(10,025	)		—			—			(10,025	)
Net cash used in investing activities		—			(13,193	)		(465,776	)		(1,701	)		(480,670	)
Investing Activities:
Proceeds from issuance of common stock		384,872			—			—			—			384,872
Payments for unit issuance costs		(22,308	)		—			—			—			(22,308	)
Repurchase of common stock		(19,571	)		—			—			—			(19,571	)
Proceeds from Note Purchase Agreement		—			14,150			—			—			14,150
Payment on Note Purchase Agreement		—			(14,150	)		—			—			(14,150	)
Proceeds from First Lien		—			117,500			—			—			117,500
Proceeds from Second Lien		—			75,000			—			—			75,000
Payments on put financing		—			(330	)		—			—			(330	)
Payments for debt issuance costs		—			(4,172	)		—			—			(4,172	)
Net cash provided by financing activities		342,993			187,998			—			—			530,991
Net increase in cash and cash equivalents		54,316			2,619			1,526			3,928			62,389
Cash and cash equivalents — beginning of period		—			—			—			—			—
Cash and cash equivalents — end of period		54,316			2,619			1,526			3,928			62,389

F-22

ENERGY XXI GULF COAST, INC.
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 14 — Subsequent Events

Acquisition: On June 7, 2006, Energy XXI 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.

Energy XXI 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.

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.

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.

F-23

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2006

F-24

ENERGY XXI GULF COAST INC.
  
CONSOLIDATED BALANCE SHEET
March 31, 2007
(Unaudited) (In thousands, except share information)

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	6,475
Accounts receivable
Oil and natural gas sales		40,818
Joint interest billings		14,961
Insurance		109
Prepaid expenses and other current assets		44,227
Royalty deposit		2,175
Derivative financial instruments		15,543
TOTAL CURRENT ASSETS		124,308
Oil and natural gas properties — full cost method of accounting, including $199,780 of unproved oil and natural gas properties and net of accumulated depreciation, depletion and amortization of $107,594		925,906
Derivative financial instruments		4,508
Debt issuance costs net of accumulated amortization on $1,223		2,420
TOTAL ASSETS	$	1,057,142
LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts payable	$	47,145
Advances from joint interest partners		6,295
Undistributed oil and natural gas proceeds		17
Accrued liabilities		6,799
Income and franchise taxes payable		1,512
Deferred income taxes		2,287
Derivative financial instruments		4,073
Current maturities of long-term debt		9,540
TOTAL CURRENT LIABILITIES		77,668
Long-term debt, less current maturities		532,361
Deferred income taxes		12,628
Asset retirement obligations		45,981
TOTAL LIABILITIES		668,638
STOCKHOLDER’S EQUITY
Common stock, $0.01 par value, 1,000,000 shares authorized and 100,000 issued at March 31, 2007		1
Additional paid-in capital		358,375
Retained earnings		25,140
Accumulated other comprehensive income, net of tax		4,988
TOTAL STOCKHOLDER’S EQUITY		388,504
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,057,142

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

F-25

ENERGY XXI GULF COAST INC.
  
CONSOLIDATED STATEMENTS OF INCOME
Three Months and Nine Months Ended March 31, 2007
(Unaudited) (In thousands)

	Three Months			Nine Months
REVENUES
Oil sales	$	42,777		$	121,882
Natural gas sales		34,831			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		28,361			87,369
Accretion of asset retirement obligation		877			2,619
General and administrative expense		10,570			26,659
Gain on derivative financial instruments		(1,552	)		(3,110	)
TOTAL COSTS AND EXPENSES		51,432			150,084
OPERATING INCOME		26,176			72,484
OTHER INCOME (EXPENSE)
Interest income		265			1,247
Interest expense		(12,638	)		(39,626	)
TOTAL OTHER INCOME (EXPENSE)		(12,373	)		(38,379	)
INCOME BEFORE INCOME TAXES		13,803			34,105
PROVISION FOR INCOME TAXES		3,988			11,976
NET INCOME	$	9,815		$	22,129

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

F-26

ENERGY XXI GULF COAST INC.
  
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended March 31, 2007
(Unaudited) (In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	22,129
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense		3,955
Unrealized loss on derivative financial instruments		18,527
Accretion of asset retirement obligations		2,619
Depletion, depreciation, and amortization		87,369
Write-off of debt issuance costs-net		5,998
Changes in operating assets and liabilities
Accounts receivable		28,481
Prepaid expenses and other current assets		(35,096	)
Accounts payable and other liabilities		7,147
NET CASH PROVIDED BY OPERATING ACTIVITIES		141,129
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of properties		(302,481	)
Capital expenditures		(248,799	)
Proceeds from the sale of oil and natural gas properties		1,400
NET CASH USED IN INVESTING ACTIVITIES		(549,880	)
CASH FLOWS FROM FINANCING ACTIVITIES
Contribution from parent		83,883
Proceeds from long-term debt		364,000
Payments on long-term debt		(24,625	)
Payments on put financing		(7,030	)
Debt issuance costs		(4,741	)
Other		(405	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		411,082
NET INCREASE IN CASH AND CASH EQUIVALENTS		2,331
CASH AND CASH EQUIVALENTS, beginning of period		4,144
CASH AND CASH EQUIVALENTS, end of period	$	6,475

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

F-27

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007

Note 1 — Basis of Presentation

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 our audited consolidated financial statements as of and for the period from inception (February 7, 2006) through June 30, 2006 included elsewhere in this registration statement.

Note 2 — Condensed Consolidating Financial Statements

The following unaudited condensed consolidating financial statements as of and for the nine months ended March 31, 2007 of Energy XXI (Bermuda) Limited, are presented pursuant to Rule 3-10 of Regulation S-X. Energy XXI Gulf Coast, Inc. is an issuer (the “Subsidiary Issuer”) of 10% senior notes that are fully and unconditionally guaranteed by its parent, Energy XXI (Bermuda) Limited as well as each of its subsidiaries, Energy XXI Texas, LP, Energy XXI Texas GP, LLC and Energy XXI GOM, LLC (collectively, the “Subsidiary Guarantors”). Energy XXI and the Subsidiary Guarantors are 100% owned by Energy XXI (Bermuda) Limited.

The indenture covering the senior notes limits EXXI and the Subsidiary Guarantors ability to transfer or sell assets, make investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of substantially all of their assets, enter into transactions with affiliates or engage in businesses other than the oil and gas business (in thousands).

	March 31, 2007
	Parent		Subsidiary Issuer			Subsidiary Guarantors			Other Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents		2,681		5,628			848			1,020		—			10,177
Receivables:
Oil and gas sales		—		2,852			37,966			—		—			40,818
Joint interest billing		—		14,809			152			—		—			14,961
Insurance Receivable		—		(6,522	)		6,631			—		—			109
Other		—		196			(201	)		5		—			—
Intercompany		80,976		433,070			(433,072	)		2,906		(83,880	)		—
Prepaid expenses and other assets		405		40,600			3,731			3,965		—			48,701
Royalty deposit		—		—			2,175			—		—			2,175
Derivative instruments		—		15,543			—			—		—			15,543
Total current assets		84,062		506,176			(381,770	)		7,896		(83,880	)		132,484
Oil and gas properties — full cost method of accounting		—		408,970			516,936			—		—			925,906
Other property and equipment		—		—			—			3,036		—			3,036
Total property and equipment		—		408,970			516,936			3,036					928,942
Investments in subs		282,611		—			—			378,593		(661,204	)		—
Derivative instruments		—		4,508			—			—		—			4,508
Deferred taxes		—		6,179			—			—		(6,179	)		—
Other assets		—		2,421			—			13		—			2,434
Total assets	$	366,673	$	928,254		$	135,166		$	389,538	$	(751,263	)		1,068,368

F-28

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007

Note 2 — Condensed Consolidating Financial Statements  – (continued)

	March 31, 2007
	Parent		Subsidiary Issuer			Subsidiary Guarantors			Other Subsidiaries			Eliminations			Consolidated
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		3		16,923			30,217			(24	)		—			47,119
Amounts due joint interest owners		—		1,903			4,392			—			—			6,295
Accrued liabilities		60		7,638			(719	)		1,348			—			8,327
Income and franchise taxes payable		—		1,512			—			—			—			1,512
Deferred income taxes		—		2,287			—			—			—			2,287
Derivative instruments		—		4,073			—			—			—			4,073
Current maturities of long-term debt		—		9,540			—			94			—			9,634
Total current liabilities		63		43,876			33,890			1,418			—			79,247
Long-term debt		—		532,361			—			351			—			532,712
Deferred income taxes		—		—			18,807			—			(6,179	)		12,628
Asset retirement obligations		—		5,731			40,250			—			—			45,981
Other liabilities		—		—			—			1,531			—			1,531
Total liabilities		63		581,968			92,947			3,300			(6,179	)		672,099
Stockholders’ equity:
Preferred Stock, $.01 par value, 2,500,000 shares authorized, and no shares issued at October 31, 2006		—		—			—			—			—			—
Common stock, $.001 par value, 400,000,000 shares authorized, 84,049,115 issued at March 31, 2007		83		1			—			—			(1	)		83
Additional paid-in capital		362,334		358,375			—			386,708			(745,083	)		362,334
Retained earnings		4,193		(17,078	)		42,219			(470	)		—			28,864
Other comprehensive income, net of tax		—		4,988			—			—			—			4,988
Total stockholders’ equity		366,610		346,286			42,219			386,238			(745,084	)		396,270
Total liabilities and stockholders’ equity		366,673		928,254			135,166			389,538		$	(751,263	)		1,068,368

F-29

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007

Note 2 — Condensed Consolidating Financial Statements  – (continued)

	Nine Month Period Ended March 31, 2007
	Parent			Subsidiary Issuer			Subsidiary Guarantors		Other Subsidiaries			Consolidated
Revenues
Oil sales		—			15,976			105,906		—			121,882
Gas sales		—			52,104			48,582		—			100,686
Total revenues		—			68,080			154,488		—			222,568
Operating Expense:
Lease operating expenses		—			5,200			28,438		—			33,638
Production taxes		—			2,037			872		—			2,909
Depreciation, depletion and amortization		—			29,123			58,247		685			88,055
Accretion of asset retirement obligation		—			213			2,406		—			2,619
General and administrative		541			15,029			11,631		(696	)		26,505
Derivative gain		—			(3,110	)		—		—			(3,110	)
Total operating expenses		541			48,492			101,594		(11	)		150,616
Income (loss) from operations		(541	)		19,588			52,894		11			71,952
Other income (expenses):
Interest income		311			909			338		41			1,599
Interest expense		—			(39,626	)		—		(27	)		(39,653	)
Net income (loss) before income taxes		(230	)		(19,129	)		53,232		25			33,898
Provision for income taxes		—			(6,831	)		18,807		—			11,976
Net income (loss)		(230	)		(12,298	)		34,425		25			21,922

F-30

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007

Note 2 — Condensed Consolidating Financial Statements  – (continued)

	Nine Months Period Ended March 31, 2007
	Parent			Subsidiary Issuer			Subsidiary Guarantors			Other Subsidiaries			Consolidated
Operating Activities:
Net Income (loss)	$	(230	)	$	(12,298	)	$	34,425		$	25		$	21,922
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income tax		—			(14,853	)		18,807			—			3,954
Unrealized loss on derivative instrument		—			18,527			—			—			18,527
Accrued interest classified with put premuum financing		—			2,619			—			—			2,619
Depletion, depreciation, and amortiztion		—			29,123			58,247			685			88,055
Amortization of debt issuance costs		—			5,998			—			—			5,998
Changes in operating assets and liabilities:
Accounts receivable		—			11,334			24,468			5			35,807
Intercompany		(65,008	)		(48,532	)		111,566			1,974			—
Prepaid expenses and other current assets		(267	)		(32,810	)		(2,390	)		(4,034	)		(39,501	)
Accounts payable (including intercompany)		3			24,395			(3,602	)		589			21,385
Net cash provided by (used in) operating activities	$	(65,502	)	$	(16,497	)	$	241,521		$	(756	)	$	158,766
Investing Activities:
Business acquired		—			(302,481	)		—			—			(302,481	)
Purchases of property and equipment		—			(5,200	)		(243,599	)		(2,152	)		(250,951	)
Proceeds from the sale of oil and natural gas properties		—			—			1,400			—			1,400
Other		1,333			—			—			—			1,333
Net cash provided by (used in) investing activities	$	1,333		$	(307,681	)	$	(242,199	)	$	(2,152	)	$	(550,699	)
Financing Activities:														—
Proceeds from issuance of common stock		13,167			—			—			—			13,167
Debt issuance costs		—			(4,754	)		—			—			(4,754	)
Proceeds from long term debt		—			364,000			—			—			364,000
Payment on long term debt		—			(24,625	)		—			—			(24,625	)
Payments on put financing		—			(7,030	)		—			—			(7,030	)
Other		(633	)		(404	)		—			—			(1,037	)
Net cash provided by financing activities	$	12,534		$	327,187		$	—		$	—		$	339,721
Net increase (decrease) in cash and cash equivalents		(51,635	)		3,009			(678	)		(2,908	)		(52,212	)
Cash and cash equivalents — beginning of period		54,316			2,619			1,526			3,928			62,389
Cash and cash equivalents — end of period	$	2,681		$	5,628		$	848		$	1,020		$	10,177

F-31

ENERGY XXI GULF COAST, INC.
  
CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007

Note 3 — Shareholder’s Equity

Follows is a reconciliation of stockholder’s equity for the nine month period ended March 31, 2007 (in thousands):

					Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Common Stock
	Shares		Amount
Balance, as of June 30, 2006		100,000	$	1	$	274,492	$	3,011	$	(4,552	)	$	272,952
Comprehensive loss:
Net income		—		—		—		22,129		—			22,129
Contributions from parent						83,883							83,883
Unrealized gain on derivative financial instruments, net of tax		—		—		—		—		9,550			9,550
Balance as of March 31, 2007		100,000	$	1	$	358,375	$	25,140		4,988		$	388,504

F-32

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

F-33

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-34

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
Undistributed oil and natural gas proceeds		5,617
Accrued liabilities		5,846
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		199,644
Asset retirement obligations		37,844
Derivative financial instruments.		590
Other liabilities		641
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, 400,000,000 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-35

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-36

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-37

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-38

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

F-39

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

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.

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

F-40

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

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.

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,

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

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.

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

F-42

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

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 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. 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.

F-43

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

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.

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	)

F-44

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 3 — Acquisition  – (continued)

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.

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,

F-45

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 4 — Long-Term Debt  – (continued)

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		72,772
2011		—
Thereafter		—
Total	$	209,228
Less current portion.		(9,584	)
Long-term debt	$	199,644

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.

F-46

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 6 — Derivative Financial Instruments  – (continued)

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.

F-47

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 6 — Derivative Financial Instruments  – (continued)

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

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

F-48

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 7 — Income Taxes  – (continued)

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of 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-49

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 8 — Stockholders’ Equity  – (continued)

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

F-50

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 11 — Related Party Transactions  – (continued)

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.

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.

F-51

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 13 — Commitments and Contingencies  – (continued)

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.

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

F-52

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 16 — Subsequent Events  – (continued)

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.

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.

F-53

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

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

F-54

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 18 — Supplementary Oil and Gas Information (Unaudited)  – (continued)

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-55

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006

Note 18 — Supplementary Oil and Gas Information (Unaudited)  – (continued)

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-56

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007

F-57

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-58

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, 400,000,000 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-59

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-60

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-61

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-62

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

F-63

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007
(Unaudited)

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

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.

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 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. The adoption of SAB 108 did not have a material impact on the consolidated financial statements of the Company.

F-64

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007
(Unaudited)

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

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.

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

F-65

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007
(Unaudited)

Note 2 — Acquisitions  – (continued)

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-66

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007
(Unaudited)

Note 2 — Acquisitions  – (continued)

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

F-67

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007
(Unaudited)

Note 3 — Long-Term Debt  – (continued)

$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%.

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 of Debt 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.

F-68

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007
(Unaudited)

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.

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.

F-69

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007
(Unaudited)

Note 5 —  Derivative Financial Instruments  – (continued)

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-70

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007
(Unaudited)

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.

F-71

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007
(Unaudited)

Note 10 — Commitments and Contingencies  – (continued)

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

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-72

ENERGY XXI (BERMUDA) LIMITED
  
CARVE-OUT FINANCIAL STATEMENTS FOR CASTEX
June 30, 2006

F-73

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-74

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-75

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.

F-76

ENERGY XXI (BERMUDA) LIMITED
  
CARVE-OUT FINANCIAL STATEMENTS FOR CASTEX
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
June 30, 2006

3. Summary of Significant Accounting Policies  – (continued)

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.

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

F-77

ENERGY XXI (BERMUDA) LIMITED
  
CARVE-OUT FINANCIAL STATEMENTS FOR CASTEX
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
June 30, 2006

4. Supplemental Information on Oil and Gas Reserves (Unaudited)  – (continued)

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.

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-78

MARLIN ENERGY OFFSHORE L.L.C., MARLIN TEXAS GP, L.L.C.
AND MARLIN TEXAS, L.P.
  
COMBINED FINANCIAL STATEMENTS

F-79

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-80

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C.
AND MARLIN TEXAS, L.P.
  
COMBINED BALANCE SHEETS

	March 31,2006		December 31,
			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-81

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 March 31, 2006		For the Year Ended December 31,
			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-82

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-83

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 March 31, 2006			For the Year Ended December 31,
				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-84

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C.
AND MARLIN TEXAS, L.P.
  
NOTES TO COMBINED FINANCIAL STATEMENTS

Note 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.

F-85

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C.
AND MARLIN TEXAS, L.P.
  
NOTES TO COMBINED FINANCIAL STATEMENTS

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

Cash and Cash Equivalents

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

F-86

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C.
AND MARLIN TEXAS, L.P.
  
NOTES TO COMBINED FINANCIAL STATEMENTS

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

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.

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.

Note 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.

Note 3 — Acquisitions

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).

F-87

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C.
AND MARLIN TEXAS, L.P.
  
NOTES TO COMBINED FINANCIAL STATEMENTS

Note 3 — Acquisitions  – (continued)

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).

Note 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, 2006			December 31,
				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

Note 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, 2006			Year Ending December 31,
				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

Note 6 — Supplemental Cash Flow Information

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

F-88

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C.
AND MARLIN TEXAS, L.P.
  
NOTES TO COMBINED FINANCIAL STATEMENTS

Note 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.

Note 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, 2006		Year Ending December 31,
Customer			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.

Note 9 — Fair Value of Financial Instruments

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-89

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C.
AND MARLIN TEXAS, L.P.
  
NOTES TO COMBINED FINANCIAL STATEMENTS

Note 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

F-90

MARLIN ENERGY OFFSHORE, L.L.C., MARLIN TEXAS GP, L.L.C.
AND MARLIN TEXAS, L.P.
  
NOTES TO COMBINED FINANCIAL STATEMENTS

Note 10 — Supplementary Oil and Gas Information (Unaudited)  – (continued)

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.

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, 2006			December 31,
				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, 2006			Year Ending December 31,
				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-91

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-92

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-94
Statement of Revenues and Direct Operating Expense		F-95
Notes to Statements of Revenues and Direct Operating Expenses		F-96

F-93

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-94

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-95

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

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

F-96

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

Note 2 — Summary of Significant Accounting Policies  – (continued)

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.

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		15,193		34,353
December 31, 2005		10,929		29,159
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

F-97

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

Note 3 — Supplemental Information on Oil and Gas Reserves (Unaudited)  – (continued)

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 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-98

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-99

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-100

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 March 31, 2007		Pro Forma Adjustments									Energy XXI Pro Forma March 31, 2007
			Loan Proceeds			Pogo			Other Costs
	(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-101

ENERGY XXI (BERMUDA) LIMITED
  
PRO FORMA CONSOLIDATED INCOME STATEMENT
Nine Month Period Eended 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 March 31, 2007			Pro Forma Adjustments						Energy XXI Pro Forma Nine Months Ended March 31, 2007
				Castex			Pogo
	(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.

F-102

ENERGY XXI (BERMUDA) LIMITED
  
PRO FORMA CONSOLIDATED INCOME STATEMENT
Nine Month Period Eended March 31, 2007
(Unaudited)

Pro Forma Adjustments Related to the Acquisition  – (continued)

(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.

(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-103

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) to June 30, 2006			Pro Forma Adjustments									Energy XXI
				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).

F-104

ENERGY XXI (BERMUDA) LIMITED
  
PRO FORMA CONSOLIDATED INCOME STATEMENT
Period From July 25, 2005 (Inception) to June 30, 2006
(Unaudited)

Basis of Presentation  – (continued)

(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.

(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-105

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. Ryder Scott Company, LP provided the Company with December 31, 2006, 2005, 2004, 2003 and 2002 economic data bases which were used by the Company in the construction of the June 30, 2006, 2005, 2004 and 2003 Pro Forma reserve disclosures. 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-106

ENERGY XXI (BERMUDA) LIMITED
  
PRO FORMA RESERVE INFORMATION
Periods Ended June 30, 2006, 2005 and 2004

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-107

ENERGY XXI (BERMUDA) LIMITED
  
PRO FORMA RESERVE INFORMATION
Periods Ended June 30, 2006, 2005 and 2004

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-108

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of Directors and Officers

Section 145 of the Delaware General Corporation Law (“DGCL”) provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. Section 145 further provides that a corporation similarly may indemnify any such person serving in any such capacity who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees) actually and reasonably incurred in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Delaware Court of Chancery or such other court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all of the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Delaware Court of Chancery or such other court shall deem proper. Our certificate of incorporation and bylaws provide that indemnification shall be to the fullest extent permitted by the DGCL for all our current or former directors or officers. As permitted by the DGCL, our certificate of incorporation provides that we will indemnify our directors against liability to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except (1) for any breach of the director’s duty of loyalty to us or our stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or knowing violation of law, (3) under Section 174 of the DGCL or (4) for any transaction from which a director derived an improper personal benefit.

Item 21. Exhibits and Financial Statement Schedules

3.1	Certificate of Incorporation of Energy XXI (Bermuda) Limited
3.2	Certificate of Incorporation on Change of Name of Energy XXI (Bermuda) Limited
3.3	Certificate of Deposit of Memorandum of Increase of Share Capital of Energy XXI (Bermuda) Limited
3.4	Altered Memorandum of Association of Energy XXI (Bermuda) Limited
3.5	Bye-Laws of Energy XXI (Bermuda) Limted
3.6	Certificate of Incorporation of Energy XXI Gulf Coast, Inc.
3.7	Bylaws of Energy XXI Gulf Coast, Inc.
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 Vinson & Elkins LLP
5.2	Opinion of Appleby Hunter Bailhache

II-1

10.1	Amended and Restated First Lien Credit Agreement, dated June 8, 2007, among the Issuer, the guarantors named therein, the various financial institutions, as lenders, The Royal Bank of Scotland plc, as Administrative Agent, RBS Securities Corporation and BNP Paribas, as Syndication Agent, and Guaranty Bank, FSB and BMO Capital Markets Financing, Inc., as Co-Documentation Agents
10.2	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and John D. Schiller, Jr.
10.3	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and Steve Weyel
10.4	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and David West Griffin
10.5	2006 Long-Term Incentive Plan of Energy XXI Services, LLC
10.6	Form of Restricted Stock Grant Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC
10.7	Form of Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC
10.8	Appointment letter dated August 31, 2005 for William Colvin
10.9	Appointment letter dated August 31, 2005 for David Dunwoody
10.10	Appointment letter dated April 16, 2007 for Hill Feinberg
10.11	Appointment letter dated April 24, 2007 for Paul Davison
10.12	Letter Agreement dated September 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.
10.13	Assumption and Indemnity Agreement dated September 15, 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.
10.14	Purchase and Sale Agreement dated as of June 6, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.15	First Amendment to Purchase and Sale Agreement dated as of July 5, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.16	Second Amendment to Purchase and Sale Agreement dated as of July 10, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.17	Third Amendment to Purchase and Sale Agreement dated as of July 27, 2006 by and between Castex Energy, Inc., Castex Energy 1995, L.P., Browning Oil Company, Inc., Flare Resources Inc., J&S Oil and Gas, LLC, Kitty Hawk Energy, L.L.C. and Rabbit Island, L.P., as the Sellers, and Energy XXI Gulf Coast, Inc. as the Buyer.
10.18	Purchase and Sale Agreement dated as of February 21, 2006 by and between Marlin Energy, L.L.C., as Seller, and Energy XXI Gulf Coast, Inc., as Buyer.
10.19	Joinder and Amendment to Purchase and Sale Agreement dated as of March 2, 2006 by and among Marlin Energy, L.L.C., Energy XXI Gulf Coast, Inc. and Energy XXI (US Holdings) Limited.
10.20	Second Amendment to Purchase and Sale Agreement dated as of March 12, 2006 by and among Marlin Energy, L.L.C., Energy XXI Gulf Coast, Inc. and Energy XXI (US Holdings) Limited.
10.21	Participation Agreement dated as January 26, 2007 by and between Centurion Exploration Company and Energy XXI Gulf Coast, Inc.
10.22	Purchase and Sale Agreement, dated as of April 24, 2007, by and between Pogo Producing Company and Energy XXI GOM, LLC
10.23	Registration Rights Agreement dated as of June 8, 2007 among Energy XXI Gulf Coast, Inc., the Guarantors named therein, the Initial Purchasers named therein, and the Purchasers named therein.
12.1	Ratio of Earnings to Fixed Charges
21.1	Subsidiary List

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23.1	Consent of UHY LLP (Energy XXI Gulf Coast, Inc.)
23.2	Consent of UHY LLP (Energy XXI (Bermuda) Limited))
23.3	Consent of UHY LLP (Castex)
23.4	Consent of UHY LLP (Pogo)
23.5	Consent of Grant Thornton LLP
23.6	Consent of Netherland, Sewell & Associates, Inc.
23.7	Consent of Miller and Lents, Ltd.
23.8	Consent of Ryder Scott Company, LP
25.1	Form T-1 Statement of Eligibility and Qualification under the Trust Indenture Act of 1939 of the trustee under the Senior Indenture
99.1	Form of Letter of Transmittal
99.2	Form of Notice of Guaranteed Delivery

Item 22. Undertakings

Each undersigned registrant hereby undertakes:

(a)(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;

(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. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement; provided, however, that paragraphs (a)(1)(i) and (a)(1)(ii) do not apply if the registration statement is on Form S-3, Form S-8 or Form F-3, and the information required to be included in a post-effective amendment by those paragraphs is contained in periodic reports filed with or furnished to the Commission by the registrant pursuant to section 13 or section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the registration statement.

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment 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 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.

(b) That, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrants annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to section 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 the initial bona fide offering thereof.

(c) To respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send

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the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

(d) To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in this registration statement when it became effective.

(e) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy 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.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, Energy XXI Gulf Coast, Inc. certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on August 22, 2007.

Energy XXI Gulf Coast, Inc.

By: /s/ Rick Fox
Rick Fox
Chief Financial Officer, Treasurer and Secretary

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and directors of Energy XXI Gulf Coast, Inc. (the “Company”) hereby constitutes and appoints David West Griffin his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file this registration statement under the Securities Act of 1933, as amended, and any or all amendments (including, without limitation, post-effective amendments), with all exhibits and any and all documents required to be filed with respect thereto, with the Securities and Exchange Commission or any regulatory authority, granting unto such attorney-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same, as fully to all intents and purposes as he himself might or could do, if personally present, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities and on August 22, 2007.

Signature	Title
/s/ John D. Schiller, Jr. John D. Schiller, Jr.	Director
/s/ Steven A. Weyel Steven A. Weyel	Director
/s/ David West Griffin David West Griffin	Director

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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 August 22, 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	August 22, 2007
/s/ DAVID WEST GRIFFIN David West Griffin	Director, Chief Financial Officer (Principal Financial Officer)	August 22, 2007
/s/ HUGH A. MENOWN Hugh A. Menown	Chief Accounting Officer (Principal Accounting Officer)	August 22, 2007
/s/ WILLIAM COLVIN William Colvin	Director	August 22, 2007
/s/ DAVID M. DUNWOODY David M. Dunwoody	Director	August 22, 2007
/s/ HILL A. FEINBERG Hill A. Feinberg	Director	August 22, 2007
/s/ PAUL DAVISON Paul Davison	Director	August 22, 2007

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, Energy XXI Texas GP, LLC certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on August 22, 2007.

Energy XXI Texas GP, LLC

By: /s/ Rick Fox
Rick Fox
Chief Financial Officer, Treasurer and Secretary

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and managers of Energy XXI Texas LP, LLC (the “Company”) hereby constitutes and appoints David West Griffin his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file this registration statement under the Securities Act of 1933, as amended, and any or all amendments (including, without limitation, post-effective amendments), with all exhibits and any and all documents required to be filed with respect thereto, with the Securities and Exchange Commission or any regulatory authority, granting unto such attorney-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same, as fully to all intents and purposes as he himself might or could do, if personally present, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities and on August 22, 2007.

Signature	Title
/s/ John D. Schiller, Jr. John D. Schiller, Jr.	Manager
/s/ Steven A. Weyel Steven A. Weyel	Manager
/s/ David West Griffin David West Griffin	Manager

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, Energy XXI GOM, LLC certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on August 22, 2007.

Energy XXI GOM, LLC

By: /s/ Rick Fox
Rick Fox
Chief Financial Officer, Treasurer and Secretary

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and managers of Energy XXI GOM, LLC (the “Company”) hereby constitutes and appoints David West Griffin his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file this registration statement under the Securities Act of 1933, as amended, and any or all amendments (including, without limitation, post-effective amendments), with all exhibits and any and all documents required to be filed with respect thereto, with the Securities and Exchange Commission or any regulatory authority, granting unto such attorney-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same, as fully to all intents and purposes as he himself might or could do, if personally present, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities and on August 22, 2007.

Signature	Title
/s/ John D. Schiller, Jr. John D. Schiller, Jr.	Manager
/s/ Steven A. Weyel Steven A. Weyel	Manager
/s/ David West Griffin David West Griffin	Manager

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, Energy XXI Texas, LP certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on August 22, 2007.

Energy XXI Texas, LP

By Energy XXI Texas GP, LLC
its General Partner

By: /s/ Rick Fox
Rick Fox
Chief Financial Officer, Treasurer and Secretary

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