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

 

FORM 10-K

 

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

For the Fiscal Year Ended June 30, 2009

OR

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

For the Transition Period from  to 

Commission File Number 001-33628

 

ENERGY XXI (BERMUDA) LIMITED

(Exact Name of Registrant as Specified in Its Charter)

Bermuda	98-0499286
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

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

441-295-2244

(Registrant’s Telephone Number, Including Area Code)

 

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, par value $.001 per share	The NASDAQ Stock Market LLC

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

 

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

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

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $103,366,446 based on the closing sale price of $0.79 per share as reported on NASDAQ on December 31, 2008.

The number of shares of the registrant’s common stock outstanding on August 26, 2009, was 145,800,008.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2009 Annual Meeting of Shareholders, which will be filed within 120 days of June 30, 2009, are incorporated by reference into Part III of this Annual Report on Form 10-K.

ENERGY XXI (BERMUDA) LIMITED
  
TABLE OF CONTENTS

	Page
PART I
Cautionary Statement Regarding Forward-Looking Statements		ii
Item 1 Business		1
Item 1A Risk Factors		6
Item 1B Unresolved Staff Comments		21
Item 2 Properties		21
Item 3 Legal Proceedings		25
Item 4 Submission of Matters to a Vote of Security Holders		25
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
Item 6 Selected Financial Data		28
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 7A Quantitative and Qualitative Disclosures About Market Risk		48
Item 8 Financial Statements and Supplementary Data		49
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		85
Item 9A Controls and Procedures		85
Item 9B Other Information		85
PART III
Item 10 Directors, Executive Officers and Corporate Governance		86
Item 11 Executive Compensation		86
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		86
Item 13 Certain Relationships and Related Transactions, and Director Independence		86
Item 14 Principal Accounting Fees and Services		86
PART IV
Item 15 Exhibits, Financial Statement Schedules		86
Glossary of Oil and Natural Gas Terms		92
Signatures		94

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Forward-Looking Statements

The statements contained in this report, other than statements of historical fact, constitute forward-looking statements. Such statements include, without limitation, all statements as to the production of oil and gas, product prices, oil and gas reserves, drilling and completion results, capital expenditures and other such matters. These statements relate to events and/or future financial performance and involve known and unknown risks, uncertainties and other factors that may cause our actual results, levels of activity, performance or achievements or the industry in which we operate to be materially different from any future results, levels of activity, performance or achievements expressed or implied by the forward-looking statements. These risks and other factors include those listed under Item 1A “Risk Factors” and those described elsewhere in this report.

In some cases, you can identify forward-looking statements by our use of terms such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “intends,” “predicts,” “potential” or the negative of these terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. In evaluating these statements, you should specifically consider various factors, including the risks outlined under “Risk Factors.” These factors may cause our actual results to differ materially from any forward-looking statement. Factors that could affect our actual results and could cause actual results to differ materially from those in forward-looking statements include, but are not limited to, the following:

• our business strategy;

• our financial position;

• the extent to which we are leveraged

• our cash flow and liquidity;

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

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

• uncertainties in estimating our oil and gas reserves;

• replacing our oil and gas reserves;

• uncertainties in exploring for and producing oil and gas;

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

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

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

• availability, cost and adequacy of insurance coverage;

• competition in the oil and gas industry;

• our inability to retain and attract key personnel;

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

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

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Moreover, neither we nor any other person assumes responsibility for the accuracy and completeness of these forward-looking statements. We do not intend to update any of the forward-looking statements after the date of this report to conform prior statements to actual results.

ii

PART I

Item 1. Business

Overview

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

Our exploration and production activities commenced in April 2006 upon our acquisition of Marlin Energy Offshore, LLC and its affiliates (“Marlin”), whose Gulf of Mexico assets consisted of working interests in 34 oil and gas fields with 108 producing wells. In July 2006, we acquired additional oil and gas working interests in 21 onshore and inland water Louisiana Gulf Coast fields from affiliates of Castex Energy, Inc. (“Castex”). On June 8, 2007, we acquired certain oil and natural gas properties in the Gulf of Mexico (the “Pogo Properties”) from Pogo Producing Company (the “Pogo Acquisition”). The Pogo Acquisition included working interests in 28 oil and gas fields.

Our operations are geographically focused and we target acquisitions of oil and gas properties with which we can add value by increasing production and ultimate recovery of reserves, whether through exploitation or exploration, often using reprocessed seismic data to identify previously overlooked opportunities. For the year ended June 30, 2009, approximately 58 percent of our capital expenditures were associated with the exploitation of existing properties. During the past two years, we have sought to maintain our production at South Timbalier 21 and have gradually shifted our exploitation focus to the properties acquired from Pogo Producing on June 8, 2007. For the year ended June 30, 2009, production from those properties averaged 7.0 thousand barrels of oil equivalent per day (“MBOED”) and we spent approximately $50 million of capital on these acquired assets.

At June 30, 2009, our total proved reserves were 53.1 million barrels of oil equivalent (“MMBOE”) of which 58 percent were oil and 64 percent were classified as proved developed. We operated or had an interest in 274 producing wells on 148,784 net developed acres, including interests in 56 producing fields. All of our properties are located on the Gulf Coast and in the Gulf of Mexico, with approximately 78 percent of our proved reserves being offshore. This concentration facilitates our ability to manage the operated fields efficiently and our high number of wellbore locations provides diversification of our production and reserves. We believe operating our assets is key to our strategy; approximately 78 percent of our proved reserves are on properties operated by us. We have a seismic database covering approximately 3,100 square miles, primarily focused on our existing operations. This database has helped us identify at least 100 development and exploration opportunities. We believe the mature legacy fields on our acquired properties will lend themselves well to our aggressive exploitation strategy and expect to identify incremental exploration opportunities on the properties.

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

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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 more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated oil gas production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

Shell Trading Company (“Shell”) accounted for approximately 65 percent, 62 percent and 35 percent of our total oil and natural gas revenues during the years ended June 30, 2009, 2008 and 2007, respectively. 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 or substantially all of our production in the event that Shell curtailed its purchases.

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. Our ability to market our oil and gas has at times been limited or delayed due to restricted or unavailable transportation space or weather damage, and cash flow from the affected properties has been and could continue to be adversely impacted.

Competition

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

Regulatory Matters

Regulation of Oil and Gas Production, Sales and Transportation

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

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

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

Environmental Regulation

Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the handling, discharge and disposition of waste

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materials, the reclamation and abandonment of wells, sites and facilities, financial assurance under the Oil Pollution Act of 1990 and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

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

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

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

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

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

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

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

• Safe Drinking Water Act, which governs underground injection and disposal activities; and

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

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

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

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

Employees

We had 119 and 114 employees at June 30, 2009 and June 30, 2008, respectively. At June 30, 2009, we had no union employees.

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Web Site Access to Reports

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

Executive Officers of the Registrant

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

Name	Age	Position	Since
John D. Schiller, Jr.	50	Chairman and Chief Executive Officer	July 2005
Steven A. Weyel	55	Director, President and Chief Operating Officer	July 2005
David West Griffin	48	Director, Chief Financial Officer	July 2005
Ben Marchive	62	Senior Vice President, Operations	April 2006
Stewart Lawrence	48	Vice President of Investor Relations and Communications	March 2007
Hugh A. Menown	51	Vice President, Chief Accounting Officer and   Chief Information Officer	May 2007
Steve Nelson	49	Vice President of Drilling and Production	April 2006
Todd Reid	46	Senior Vice President, Marketing & Risk Management	July 2006

John D. Schiller, Jr.  Mr. Schiller is our Chairman and Chief Executive Officer, and has been since our inception in 2005. Mr. Schiller’s career spans 28 years in the oil and gas industry. In addition to forming the Company, Mr. Schiller served as: interim chief executive officer of Particle Drilling, Inc. between December 2004 and November 2005; Vice President, Exploration and Development, for Devon Energy from April 2003 to December 2003 with responsibility for domestic and international activities; Executive Vice President, Exploration and Production, for Ocean Energy, Inc. from 1999 to April 2003, overseeing Ocean’s worldwide exploration, production and drilling activities; and Senior Vice President of Operations of Seagull Energy. Prior to serving in those offices, Mr. Schiller held various positions at Burlington Resources, including Engineering and Production Manager of the Gulf of Mexico Division and Corporate Acquisition Manager, and at Superior Oil where he began his career in 1981. Mr. Schiller serves on the Board of Directors of Particle Drilling, Inc., a development stage oil and gas services company, and also serves on the Board of Directors of Escape Family Resource Center, a charitable organization. He is a registered professional engineer in the State of Texas. Mr. Schiller is a charter member and past Chairman of the Petroleum Engineering Industry Board and a member of the Look College of Engineering Advisory Council at Texas A&M. Mr. Schiller graduated with honors from Texas A&M University with a Bachelor of Science in Petroleum Engineering in 1981 and was inducted into the Texas A&M University Harold Vance Department of Petroleum Engineering’s Academy of Distinguished Graduates in 2008.

Steven A. Weyel  Mr. Weyel is our President and Chief Operating Officer and has been since our inception, bringing 33 years of industry experience. Mr. Weyel is co-founder and was most recently Principal and President/COO of EnerVen LLC, a company developing and supporting strategic ventures in the emerging energy industry, which company was formed in September 2002. In August 2005, Mr. Weyel sold his membership interests and resigned his positions in EnerVen LLC to devote full time and efforts to Energy XXI. From 1999 to 2002, Mr. Weyel was President and COO of InterGen North America, a Shell-Bechtel joint venture in the merchant gas and power business. From 1994 to 1999, Mr. Weyel was with Dynegy Corporation, previously known as Natural Gas Clearinghouse and NGC Corporation, where he served in various executive leadership positions, including Executive Vice President — Integrated Energy and Senior Vice President — Power Development. Mr. Weyel has a broad range of experience in the international oil service sector, including ownership of his own firm, Resource Technology Corporation, from 1983 to 1994, where he identified a new market opportunity based on evolving technology, and created the global engineering leader in onsite energy commodity reserves evaluation. From 1976 to 1983, Mr. Weyel worked with Baker Eastern S.A. (Baker-Hughes), in numerous strategic growth roles including Managing Director for the Western Hemisphere. Mr. Weyel received his Masters in Business Administration from the University of Texas at Austin in 1989. Mr. Weyel graduated from Texas A&M University with a Bachelor of Science in Industrial Distribution in 1976.

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David West Griffin  Mr. Griffin is our Chief Financial Officer and has been since our inception, with 24 years of finance experience. Prior to inception, Mr. Griffin spent his time focusing on the formation of the company. From January 2004 to December 2004, Mr. Griffin was the Chief Financial Officer of Alon USA, a refining and marketing company. From April 2002 to January 2004, Mr. Griffin owned his own turn-around consulting business, Energy Asset Management. From 1996 to April 2002, Mr. Griffin served in various positions with InterGen, including as Chief Financial Officer for InterGen’s North American business and supervisor of financing of all of InterGen’s Latin American projects. From 1993 to 1996, Mr. Griffin worked in the Project Finance Advisory Group of UBS. From 1985 to 1993, Mr. Griffin served in various positions with Bankers Trust Company. Mr. Griffin graduated Magna Cum Laude from Dartmouth College in 1983 and received his Masters in Business Administration from Tuck Business School in 1985.

Ben Marchive  Mr. Marchive is our Senior Vice President, Operations. He has 29 years of experience in the oil and gas industry. He began his career with Superior Oil Company and gained extensive knowledge of offshore drilling, completion and production operations. He has since held management positions with Great Southern Oil & Gas, Kerr-McGee Corporation and most recently Ocean Energy, Inc. During his fourteen year tenure at Kerr-McGee, Ben managed all disciplines of engineering dealing with drilling, production operations, completions and reserve determination for the offshore division. In February 1999 Ben joined Ocean Energy, Inc. where he served as Vice President, Production North America. In this capacity, he was responsible for all Production Operations for North America Land and Offshore until his retirement in July 2003. Ben joined the company in April 2006. He is a member of the Society of Petroleum Engineers, American Petroleum Institute and American Association of Drilling Engineers. Mr. Marchive is a 1977 graduate of Louisiana State University with a Bachelor of Science degree in Petroleum Engineering.

Stewart Lawrence  Mr. Lawrence our Vice President of Investor Relations and Communications, has 22 years of financial communications experience in the energy industry. From September 2001 to March 2007, he was Manager of Investor Relations for Anadarko Petroleum Corporation. From 1996 to 2001, Mr. Lawrence was responsible for investor relations and other communications functions at MCN Energy Group, a diversified energy company that was acquired in 2001 by DTE Energy Company. Mr. Lawrence graduated Magna Cum Laude from the University of Houston with a Bachelor of Arts degree in Journalism in 1987 and a Masters in Business Administration in 1995.

Hugh A. Menown  Mr. Menown is our Vice President, Chief Accounting Officer and Chief Information Officer. He has more than 29 years of experience in mergers and acquisitions, auditing and managerial finance. Mr. Menown has served with us since August 2006. For the first seven months of 2006, Mr. Menown worked as an independent consultant in the energy industry. Prior to that time, March 2002 until December 2005, he was employed by Quanta Services, Inc., serving as Chief Financial Officer for two of Quanta’s operating companies. From 1987 to 1999, Mr. 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. He is a certified public accountant and a 1980 graduate of the University of Missouri — Columbia — with a bachelor’s degree in business administration.

Steve Nelson  Mr. Nelson is our Vice President of Drilling and Production. He has over 26 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. From April 1999 until joining us in April 2006, Mr. Nelson was employed by Ocean Energy, which was acquired by Devon Energy in May 2003, serving as U.S. Onshore Well Work Superintendent (from April 1999 until April 2000) and then as Production and Engineering Manager for U.S. Onshore for the remainder of his tenure there. 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 Bachelor of Science degree in Petroleum Engineering from the University of Oklahoma in 1983.

Todd Reid  Mr. Reid is our Senior Vice President of Marketing and Risk Management. He has 17 years of experience in the energy marketing and trading business. Most recently, Mr. Reid served as President of Houston Research & Trading Ltd. from 2003 until joining us in July 2006 in his current position. Prior to those offices, he has held senior management positions with Houston Research and Trading, Duke Energy

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Trading and Marketing, NP Energy, Louisville Gas and Electric and Dynegy. Before coming to the energy industry, Mr. Reid first learned the trading business as a market maker for six years on the floor of the Chicago Board Options Exchange and was a member of the Chicago Board of Trade. He graduated with honors from Illinois College with a Bachelor of Science in Physics and Math in 1984. Mr. Reid received his Masters in Business Administration from Washington University in St. Louis in 1986.

Item 1A. Risk Factors

Risks Related to Our Business

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

Unlike other entities that are geographically diversified, we do not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. By consummating acquisitions only in the offshore Gulf of Mexico and Gulf Coast onshore 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.

In addition, the geographic concentration of our properties in the Gulf of Mexico and Gulf Coast onshore means that some or all of the properties could be affected should the region 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, and again by Hurricanes Gustav and Ike and the oil and gas properties that we acquired in June 2007 were damaged by Hurricanes Katrina and Rita, which required us to spend a considerable amount of time and capital on inspections, repairs, debris removal, and the drilling of replacement wells. Although we maintain insurance coverage to cover a portion of these types of risks, there may be potential risks associated with our operations not covered by insurance. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss.

Because all or a number of the properties could experience many 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 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. As of June 30, 2009, we had total indebtedness of $862.8 million. 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;

• increase our vulnerability to general adverse economic and industry conditions;

• 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;

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

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

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

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

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

We expect to make substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas properties. 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. A decrease in expected revenues or adverse change in market conditions could make obtaining this financing economically unattractive or impossible.

The cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and, in some cases, ceased to provide funding to borrowers.

A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our ability to remain in compliance with the financial covenants under our revolving credit facility which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or not purse growth opportunities.

Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations. We may also be unable to obtain sufficient credit capacity with counterparties to finance the hedging of our future crude oil and natural gas production which may limit our ability to manage price risk. As a result, we may lack the capital necessary to complete potential acquisitions, obtain credit necessary to enter into derivative contracts to hedge our future crude oil and natural gas production or to capitalize on other business opportunities.

The borrowing base under our revolving credit facility will be reduced upon the next redetermination date, and may be further reduced in the future if commodity prices decline, which will limit our available funding for exploration and development.

As of June 30, 2009, total outstanding borrowings under our revolving credit facility were $234.5 million and our current borrowing base was $240 million. We expect that upon the next determination of the borrowing base under our revolving credit facility in the fall of 2009, the borrowing base under our revolving credit facility will be reduced to $199 million. The new borrowing base is subject to approval by banks holding not less than 67% of the lending commitments under our revolving credit facility, and the final borrowing base may be lower than the level recommended by the agent for the bank group.

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Our borrowing base is re-determined semi-annually by our lenders in their sole discretion. The lenders will re-determine the borrowing base based on an engineering report with respect to our natural gas and oil reserves, which will take into account the prevailing natural gas and oil prices at such time. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base re-determination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. If oil and natural gas commodity prices deteriorate, we anticipate that the revised borrowing base under our revolving credit facility may be further reduced. As a result, we may be unable to obtain adequate funding under our revolving credit facility or even be required to pay down amounts outstanding under our revolving credit facility to reduce our level of borrowing. If funding is not available when needed, or is available only on unfavorable terms, it might adversely affect our exploration and development plans as currently anticipated and our ability to make new acquisitions, each of which could have a material adverse effect on our production, revenues and results of operations.

The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and oil properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility.

The continuing financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our first lien revolving credit facility because of the deterioration of the capital and credit markets and our borrowing base.

The current credit crisis and related turmoil in the global financial systems have had an impact on our business and our financial condition, and we may face challenges if economic and financial market conditions do not improve. Historically, we have used our cash flow from operations and borrowings under our first lien revolving credit facility to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. A continuation of the economic crisis could further reduce the demand for oil and natural gas and continue to put downward pressure on the prices for oil and natural gas, which have declined significantly since reaching historic highs in July 2008. These price declines have negatively impacted our revenues and cash flows. Our current borrowing base under our first lien revolving credit facility is $240 million, which we expect to be reduced to $199 million upon the next determination in the fall of 2009.

In the future, we may not be able to access adequate funding under our first lien revolving credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. The recent declines in commodity prices, or a continuing decline in those prices, could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The turmoil in the financial markets has adversely impacted the stability and solvency of a number of large global financial institutions.

The current credit crisis makes it difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the general stability of financial markets and the solvency of specific counterparties, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity or on terms similar to existing debt or at all, or, in some cases, ceased to provide any new funding.

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We and our subsidiaries may be able to incur substantially more debt. This could further increase our leverage and attendant risks.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the indenture governing our senior notes do not fully prohibit us or our subsidiaries from doing so. At June 30, 2009, we and our subsidiary guarantors collectively would have had approximately:

• $234.5 million of secured indebtedness;

• $4.1 million of unsecured short-term indebtedness; and

• $624.2 million of other indebtedness, net of unamortized discounts.

If new debt or liabilities are added to our current debt level, the related risks that we now face could increase.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures and development and exploration efforts will depend on our ability to generate cash in the future. Our future operating performance and financial results will be subject, in part, to factors beyond our control, including interest rates and general economic, financial and business conditions. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings or other facilities will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.

If we are unable to generate sufficient cash flow to service our debt, we may be required to:

• refinance all or a portion of our debt;

• obtain additional financing;

• sell some of our assets or operations;

• reduce or delay capital expenditures, research and development efforts and acquisitions; or

• revise or delay our strategic plans.

If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure you that we would be able to take any of these actions, that these actions would enable us to continue to satisfy our capital requirements or that these actions would be permitted under the terms of the our various debt instruments.

The covenants in the indenture governing our senior notes impose restrictions that may limit our ability and the ability of our subsidiaries to take certain actions. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

The indenture governing our senior notes contains various covenants that limit our ability and the ability of our subsidiaries to, among other things:

• incur dividend or other payment obligations;

• incur indebtedness and issue preferred stock;

• sell or otherwise dispose of assets, including capital stock of subsidiaries.

If we breach any of these covenants, a default could occur. A default, if not waived, would entitle certain of our debt holders to declare all amounts borrowed under the breached indenture to become immediately due and payable, which could also cause the acceleration of obligations under certain other agreements and the termination of our credit facility. In the event of acceleration of our outstanding indebtedness, we cannot assure you that we would be able to repay our debt or obtain new financing to refinance our debt. Even if new financing is made available to us, it may not be on terms acceptable to us.

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

Our future financial condition, revenues, profitability and carrying value of our properties will depend substantially upon the prices and demand for oil and natural gas. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our revolving credit facility and through the capital markets. The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to semi-annual redeterminations based on pricing models determined by the lenders at such time. The recent decline in natural gas and oil prices has adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. It is likely that we will be subject to a reduction in our borrowing base at our next scheduled redetermination in the fall of 2009. The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth.

Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. For example, the NYMEX crude oil spot price per barrel for the period between January 1, 2009 and July 31, 2009 ranged from a high of $72.68 to a low of $33.98 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2009 to July 31, 2009 ranged from a high of $6.072 to a low of $3.253. 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 proved reserves and could 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 our properties will materially affect the quantities and present value of those reserves.

Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent,

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quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized herein. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, decommissioning liabilities and quantities of recoverable oil and gas reserves most likely will vary from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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

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

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

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

We suffered ceiling write-downs in fiscal 2009 and may suffer additional ceiling write-downs in future periods.

Under the full cost method of accounting, we are required to perform each quarter, a “ceiling test” that determines a limit on the book value of our oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unevaluated oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10%, net of related tax effects, plus the cost of unevaluated oil and gas properties, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization. Future net cash flows are based on period-end commodity prices and exclude future cash outflows related to estimated abandonment costs of proved developed properties. As of the reported balance sheet date, capitalized costs of an oil and gas producing company may not exceed the full cost limitation calculated under the above described rule based on current spot market prices for oil and natural gas. However, if prior to the balance sheet date, we enter into certain hedging arrangements for a portion of our future natural gas and oil production, thereby enabling us to receive future cash flows that are higher than the estimated future cash flows indicated by use of the spot market price as of the reported balance sheet date, these higher hedged prices are used if they qualify as cash flow hedges under the provisions of the Financial Accounting Standards Board (“FASB”) FASB Statement 133 as amended.

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Because of the significant decline in crude oil and natural gas prices, coupled with the impact of Hurricanes Gustav and Ike, we recognized a non-cash write-down of the net book value of our oil and gas properties of $117.9 million and $459.1 million in the third and second quarters of fiscal 2009, respectively. The write-downs were reduced by $179.9 million and $203.0 million pre-tax as a result of our hedging program in the third and second quarters of fiscal 2009, respectively. Additional write-downs may be required if oil and natural gas prices decline, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows.

The Company and its Subsidiaries may need to obtain bonds or other surety in order to maintain compliance with those regulations promulgated by the U.S. Minerals Management Service (the “MMS”), which, if required, could be costly and reduce borrowings available under our bank credit facility.

For offshore operations, lessees must comply with the MMS regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Shelf and removal of facilities. To cover the various obligations of lessees on the U.S. Outer Continental Shelf of the Gulf of Mexico, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. We are currently reviewing whether we are exempt from the supplemental bonding requirements of the MMS. The cost of these bonds or other surety could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. Such letter of credit would likely be issued under our first lien credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. The cost of compliance with these supplemental bonding requirements could materially and adversely affect our financial condition, cash flows and results of operations.

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

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than we. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from the Minerals Management Services (“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 present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves.

We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our natural gas and oil properties will be affected by factors such as:

• the volume, pricing and duration of our natural gas and oil hedging contracts

• supply of and demand for natural gas and oil;

• actual prices we receive for natural gas and oil;

• our actual operating costs in producing natural gas and oil;

• the amount and timing of our capital expenditures and decommissioning costs;

• the amount and timing of actual production; and

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• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

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 may increase or decrease depending on the demand for services by other oil and gas companies. While we currently have excellent relationships with oil field service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

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

We engage in exploration and development drilling activities. Any such activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of an oil or gas 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.

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;

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• 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 its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena. Currently, we have minority, non-operated interests in five deepwater leasehold blocks; four have booked proved reserves and three are producing. 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 often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically. We are currently participating in the drilling of the shallow-water, ultra deep well Davey Jones and are awaiting long lead facility equipment on block South Timbalier 168, formerly known as Blackbeard West. Both of these wildcat exploration projects have some of the same characteristics as deepwater prospects with target sizes of 200 – 400 MMBOE. Use of advanced drilling technologies, involving a higher risk of technological failure and usually higher costs.

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

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

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

As we carry out our planned drilling program, we will not serve as operator of all planned wells. We currently operate approximately 78 percent of our properties. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

• the timing and amount of capital expenditures;

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

• the operator’s expertise and financial resources;

• approval of other participants in drilling wells;

• selection of technology; and

• the rate of production of the reserves.

We depend on certain key customers for sales of our natural gas and oil. To the extent these and other customers reduce the volumes of natural gas and oil they purchase from us, or to the extent these customers cease to be creditworthy, our revenues could decline.

We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated oil gas production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

Shell Trading Company (“Shell”) accounted for approximately 65 percent, 62 percent and 35 percent of our total oil and natural gas revenues during the years ended June 30, 2009, 2008 and 2007, respectively. 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 or substantially all of our production in the event that Shell curtailed its purchases.

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. Our ability to market our oil and gas has at times been limited or delayed due to restricted or unavailable transportation space or weather damage, and cash flow from the affected properties has been and could continue to be adversely impacted.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of our vendors’, customers’ and counterparties’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’, customers’ and counterparties’ liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could reduce our cash flows.

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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. Due to 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. Although we will maintain insurance at levels we believe are appropriate and consistent with industry practice, we will not be fully insured against all risks, including high-cost business interruption insurance 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. Due to a number of recent catastrophic events like the terrorist attacks on September 11, 2001 and Hurricanes Ivan, Katrina, Rita, Gustav and Ike, 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, Rita, Gustav and Ike. As a result, insurance costs have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is as severe as it was in 2005 or 2008, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. We do not intend to put in place business interruption insurance due to its high cost. This insurance may not be economically available in the future, which could adversely impact business prospects in the Gulf of Mexico and adversely impact our operations. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

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

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

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

• require the acquisition of a permit before drilling commences;

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

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

• impose substantial liabilities for pollution resulting from operations.

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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, which could limit or restrict our operations.

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 that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

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

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the

17

power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Risks Associated with Acquisitions and Our Risk Management Program

Our acquisitions may be stretching our existing resources.

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

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

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

• operating a larger organization;

• coordinating geographically disparate organizations, systems and facilities;

• integrating corporate, technological and administrative functions;

• diverting management’s attention from other business concerns;

• an increase in our indebtedness; and

• potential environmental or regulatory liabilities and title problems.

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

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

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

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

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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 unable to find counterparties willing to enter into derivative arrangements with us or 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. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we fail to manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves.

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.

Our price risk management activities could result in financial losses or could reduce our income, which may adversely affect our cash flows.

We enter into derivative contracts to reduce the impact of natural gas and oil price volatility on our cash flow from operations. Currently, we use a combination of natural gas and crude oil put, swap and collar arrangements to mitigate the volatility of future natural gas and oil prices received.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:

• a counterparty may not perform its obligation under the applicable derivative instrument;

• there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

• the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

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

The properties we acquire may not produce as expected, may be in an unexpected condition and we may be subject to increased costs and liabilities, including environmental liabilities. Although we review properties prior to acquisition in a manner consistent with industry practices, such reviews are not capable of identifying all potential conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. We focus our review efforts on the higher-value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to fully assess their condition, any deficiencies, and development potential. Inspections may not be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Other Risks

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

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

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

We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated or the decommissioning be accelerated, such as can happen after a hurricane, 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 risk of expensive delays or loss of value if a project is unable to function as planned due to changing requirements or local opposition.

We may be taxed as a United States Corporation.

We are incorporated under the laws of Bermuda because of our long-term desire to have substantial business interests outside the United States. Currently, legislation in the United States that penalizes domestic corporations that reincorporate in a foreign country does not affect us, but future legislation could.

We plan to purchase any U.S. assets through our wholly owned subsidiary Energy XXI Inc. Energy XXI Inc. and its subsidiaries will pay U.S. taxes on U.S. income. We do not currently intend to engage in any business activity in the United States. However, there is a risk that some or all of our income could be challenged, and considered as effectively connected to a U.S. trade or business, and therefore subject to U.S. taxation. In consideration of this risk, we and our U.S. subsidiaries have implemented certain operational steps to separate the U.S. operations from our other operations. In general, employees based in the United States

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will be employees of our U.S. subsidiaries, and will be paid for their services by such U.S. subsidiaries. Salaries of our employees who are U.S. residents and who render services to the U.S. business activities will be allocated as expenses of the U.S. subsidiaries.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Our properties are primarily located in the U.S. Gulf of Mexico waters and the Gulf Coast onshore. Below are descriptions of our significant properties which at June 30, 2009 represented 74 percent of our net proved reserves and 85 percent of our future net revenues, discounted at 10%.

South Timbalier 21 Field.  We have a 100 percent working interest in the South Timbalier 21 field, located six miles offshore of Lafourche Parish, Louisiana in approximately 50 feet of water on Outer Continental Shelf (“OCS”) blocks South Timbalier 21, 22, 23, 27 and 28, as well as on two state leases. 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 320 MMBOE since production first began in 1957. There are 11 major production platforms and 79 smaller structures located throughout the field. Since July 1, 2006, we have drilled 18 gross wells. The field’s average net production for the year ended June 30, 2009 was 5.8 MBOED, accounting for approximately 30 percent of our net production for the year. Net proved reserves for the field, which is our largest (based on year-end net reserves), were 74 percent oil.

Main Pass 61 Field.  We have a 50 percent working interest in and operate the Main Pass 61 field, located near the mouth of the Mississippi River in approximately 90 feet of water. The field produces from the Upper Miocene Discorbis 12 sand, which is a black oil reservoir that is being waterflooded to maximize recovery. There are 16 producing wells and three major production platforms located throughout the field, which had net production for the year ended June 30, 2009 of 4.0 MBOED. Net proved reserves for the field, which is our second largest, were 90 percent oil.

Cote de Mer Field.  We have a 32.8 percent working interest in this field and are the operator. The discovery well was drilled to 22,261 feet in March 2009. The well was production tested at a rate of 14.6 MMCFD through test facilities. Permanent production facilities are currently being constructed and prepared for installation. First production is planned for our upcoming fiscal second quarter. This natural gas field is our third largest field by net proved reserves.

Main Pass 73/74 Field.  We have a 50 percent working interest in and operate the Main Pass 73 field, located in approximately 100 feet of water near the mouth of the Mississippi River and in close proximity to the Main Pass 61 field. This field consists of OCS blocks Main Pass 72, 73, and parts of 74. Production is from the Upper Miocene sands ranging in depths from 5,000 to 12,500 feet. Three producing platforms and one central facility are located throughout the field. We also have ownership in two Petroquest-operated

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gas-condensate wells on Main Pass 74. Average net production from the complex for the year ended June 30, 2009 was 1.7 MBOED. Net proved reserves for the field were 66 percent oil.

Viosca Knoll 1003 Field.  We have a 16.7 percent working interest in the Viosca Knoll 1003 Field, which is operated by Newfield Exploration. Viosca Knoll Block 1003 is located in 4,482 feet of water and is a one-well field development completed in the Tex W Sand. The well is a subsea tie-back to VK823 (Virgo Field) located 19.6 miles away and our net proved reserves at June 30, 2009 were 45 percent oil. This well was tested after completion during May 2007 at a rate of 40 MMCFD and 3.0 MBOD. Currently, Newfield Exploration is completing the flowline installation and facilities hook-up. Production start-up is projected in our upcoming fiscal second quarter.

South Pass 49 Field.  We have a 33 percent working interest in and operate the South Pass 49 field unit, located near the mouth of the Mississippi River in approximately 300 feet of water. The field unit consists of the Discorbis 69 and Discorbis 70 sands, ranging in depth from 8,700 to 9,400 feet, on OCS blocks South Pass 33, 48, and 49. We also have a 10 percent working interest in the non unit, which consists of 12 additional producing sands ranging in depth from 7,200 to 9,000 feet. Net proved reserves from the complex were 36 percent oil. There are 13 active completions in the field that have been shut-in since August 2008 when Hurricane Gustav damaged both the oil and gas sales pipelines. The gas and oil pipeline repairs are scheduled for November 2009. We currently estimate net field production of 0.8 MBOED to be restored in our upcoming fiscal third quarter.

East Cameron 334 Field.  We have a 51 percent working interest in and operate the East Cameron 334 Field located 90 miles South of Cameron, Louisiana in 230’ of water. The field underlies East Cameron Blocks 334, 335, 336 and West Cameron 580 and 601. Discovered in 1972, this is the 29^th largest natural gas field on the Gulf of Mexico shelf, having produced one trillion cubic feet equivalent to date from Middle to Lower Pleistocene sands at depths from 7,000 feet to 15,000 feet. There are 13 active completions in the field that have been shut-in since August 2008 due to damage that was sustained by Hurricane Gustav. After the repairs to the gas sales line are completed, we estimate net field production of 0.8 MBOED to be restored in our upcoming fiscal second quarter.

Eugene Island 330 Field.  We have a 17.5 percent working interest in this Apache operated field in 250 feet of water, located 130 miles Southwest of New Orleans. Well depths range from 6,000 to 11,000 feet. Cumulative production from the field is approximately 730 MMBOE. The field is currently shut in due to damage from Hurricane Ike. The hurricane toppled the A and C platforms, and damaged the B and D platforms in the field. Apache Corporation (“Apache”) recently assumed operatorship of the field, however, Devon Energy Corporation, the former operator, continues to operate the abandonment of the A and C platform wells and salvage of the platforms which is underway. Production from the 10 remaining wells in the field is expected to be restored by Apache in our upcoming fiscal second quarter. Net reserves are 82 percent oil.

Productive Wells

Our working interests in productive wells follow.

	June 30, 2009
	Gross		Net
Natural Gas		127.0		38.1
Crude Oil		147.0		72.5
Total		274.0		110.6

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Drilling Activity

The following table sets forth our drilling activity.

	Year Ended June 30,
	2009				2008				2007
	Gross		Net		Gross		Net		Gross		Net
Productive wells
Development		7.0		3.7		8.0		5.4		19.0		14.6
Exploratory		2.0		0.6		6.0		2.0		5.0		2.8
Total		9.0		4.3		14.0		7.4		24.0		17.4
Non productive wells
Development		—		—		2.0		2.0		8.0		8.0
Exploratory		6.0		3.5		12.0		5.0		8.0		3.6
Total		6.0		3.5		14.0		7.0		16.0		11.6

As of June 30, 2009, one gross well, representing approximately 0.17 net well, was being drilled.

Acreage

Working interests in developed and undeveloped acreage follow.

	June 30, 2009
	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Onshore		102,917		61,474		17,903		9,194		120,820		70,668
Offshore		255,653		87,310		129,489		41,873		385,142		129,183
Total		358,570		148,784		147,392		51,067		505,962		199,851

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

	Year Ended June 30,
	2010				2011				2012
	Gross		Net		Gross		Net		Gross		Net
Onshore		2,867		1,475		6,321		3,477		3,520		1,981
Offshore		37,398		6,403		33,179		1,042		—		—
Total		40,265		7,878		39,500		4,519		3,520		1,981

Capital Expenditures, Including Acquisitions and Costs Incurred

Property acquisition costs:

	Year Ended June 30,
	2009		2008		2007
	(In Thousands)
Oil and Gas Activities
Development	$	168,134	$	205,681	$	362,219
Exploration		121,554		114,639		67,140
Acquisitions		—		40,016		717,618
Administrative and Other		1,610		9,758		2,468
Capital Expenditures, Including Acquisitions		291,298		370,094		1,149,445
Asset Retirement Obligations		46,502		13,774		49,429
Total costs incurred	$	337,800	$	383,868	$	1,198,874

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Oil and Gas Production and Prices

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

	Year Ended June 30,
	2009			2008			2007
Sales Volumes per Day
Natural gas (MMcf)		47.9			75.7			50.3
Crude oil (MBbls)		11.4			13.5			7.8
Total (MBOE)		19.3			26.2			16.2
Percent of BOE from crude oil		59.1	%		51.5	%		48.1	%
Average Sales Price
Natural gas per Mcf	$	6.48		$	8.57		$	7.13
Hedge gain per Mcf		1.60			0.34			0.90
Total natural gas per Mcf	$	8.08		$	8.91		$	8.03
Crude oil per Bbl	$	67.06		$	97.72		$	62.33
Hedge gain (loss) per Bbl		3.56			(17.82	)		5.60
Total crude oil per Bbl	$	70.62		$	79.90		$	67.93
Sales price per BOE	$	55.43		$	75.40		$	52.23
Hedge gain (loss) per BOE		6.04			(8.24	)		5.48
Total sales price per BOE	$	61.47		$	67.16		$	57.71

Production Unit Costs

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

	Year Ended June 30,
	2009		2008		2007
Average Costs per BOE
Production costs
Lease operating expense
Insurance expense	$	2.72	$	1.90	$	2.14
Workover and maintenance		2.26		2.34		1.40
Direct lease operating expense		12.33		10.68		8.12
Total lease operating expense		17.31		14.92		11.66
Production taxes		0.77		0.91		0.61
Total production costs	$	18.08	$	15.83	$	12.27
Depreciation, depletion and amortization rates	$	30.78	$	32.09	$	24.68

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Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers (86 percent of our proved reserves on a valuation basis) and, the remainder, by our 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.

	June 30, 2009
	Proved Developed Producing		Proved Developed Non-Producing		Total Proved Developed		Proved Undeveloped		Total Proved Reserves
Crude oil (MBbls)		11,161		9,022		20,183		10,690		30,873
Natural gas (MMcf)		32,840		49,592		82,432		50,983		133,415
Total (MBOE)		16,635		17,287		33,922		19,187		53,109
PV-10 (In Thousands)(1)	$	391,565	$	335,321	$	726,886	$	332,887	$	1,059,773
Income taxes										71,876
10 percent discount										(17,379	)
Discounted income taxes										54,497
Standardized measure of future net discounted cash flows									$	1,005,276

(1) PV-10 reflects the present value of our estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of June 30, 2009) without giving effect to non-property related expenses such as general and administrative expenses, debt service, DD&A expense and discounted at 10 percent per year before income taxes. Prices in effect at June 30, 2009 were $69.89 per barrel of oil and $3.89 per mmbtu of natural gas, excluding differentials.

The following table summarizes our estimated future net revenues sensitivities to changes in oil and gas prices:

	June 30, 2009
	Oil (Bbl)		Gas (MMbtu)
Prices at June 30, 2009	$	69.89	$	3.89
Increase in estimated future net revenues resulting from a 10 percent increase in oil or natural gas prices (in thousands):	$	161,357	$	38,811

Netherland, Sewell & Associates, Inc., independent oil and gas consultants, in conjunction with our in-house engineers, have prepared the estimates of proved crude oil and natural gas reserves attributable to our net interests in oil and gas properties as of June 30, 2009. For further information on reserves, including information on future net cash flows and the standardized measure of discounted future net cash flows, see “Financial Statements and Supplementary Financial Information.”

Item 3. Legal Proceedings

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

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

No matters were submitted to a vote of our security holders during the fourth quarter of fiscal 2009.

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PART II

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

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

	Restricted Common Stock				Unrestricted Common Stock
	High		Low		High		Low
Fiscal 2008
First Quarter	$	6.10	$	5.15	$	6.65	$	4.79
Second Quarter		5.30		4.45		5.60		4.20
Third Quarter		4.77		3.90		5.45		3.51
Fourth Quarter		5.87		3.72		7.43		3.75
Fiscal 2009
First Quarter		5.90		3.38		6.59		2.78
Second Quarter		3.25		0.88		2.88		0.67
Third Quarter		1.05		0.48		1.25		0.28
Fourth Quarter		0.48		0.10		0.76		0.41
Fiscal 2010
First Quarter (through August 20, 2009)		0.48		0.48		0.71		0.45

As of August 20, 2009, there were approximately 284 holders of record of our common stock.

As of August 20, 2009, there were approximately 105 holders of record of our restricted common stock.

On September 9, 2008, the Board of Directors (“Board”) declared a common stock quarterly cash dividend of $0.005 per share, payable October 20, 2008 to shareholders of record on September 19, 2008. On February 6, 2009, the Board declared a cash dividend of $0.005 per common share, payable on March 13, 2009 to shareholders of record on February 20, 2009. With the borrowing base redetermination completed in April 2009, we agreed to cease declaring dividends until the next borrowing base redetermination is completed in the fall of 2009.

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Stock Performance Graph

This performance graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference in any of our filings under the Securities Act of 1933, except to the extent that we specifically incorporate the information by reference.

The graph below compares the cumulative quarterly return attained by our shareholders relative to the cumulative quarterly returns of the S&P 500 Index, the AMEX Oil Index and the Russell 3000 Index. This chart represents our freely tradable unrestricted shares from December 31, 2005 through August 20, 2009.

The performance graph was prepared based on the following assumptions: (1) $100 was invested in our common stock at $5.20 per share (the closing market price at the end of our first trading day, December 31, 2005), in the AMEX Oil Index, the S&P 500 Index and the Russell 3000 Index on December 31, 2005 and (2) dividends were reinvested on the relevant payment dates.

The stock price performance included in this graph is historical and not necessarily indicative of future stock price performance.

	Initial Investment		Cumulative Total Return
			Q3-06		Q4-06		Q1-07		Q2-07		Q3-07		Q4-07
EXXI	$	100.00	$	107.99	$	97.12	$	86.54	$	93.27	$	108.85	$	122.69
AMEX Oil Index	$	100.00	$	108.48	$	116.88	$	109.83	$	120.40	$	123.25	$	142.87
S&P 500	$	100.00	$	103.73	$	101.76	$	107.01	$	113.62	$	113.82	$	120.43
Russell 3000	$	100.00	$	104.86	$	102.33	$	106.60	$	113.66	$	114.62	$	120.72

	Initial Investment		Cumulative Total Return
			Q1-08		Q2-08		Q3-08		Q4-08		Q1-09		Q2-09
EXXI	$	100.00	$	101.92	$	99.23	$	74.42	$	133.07	$	58.46	$	15.19
AMEX Oil Index	$	100.00	$	145.94	$	158.01	$	135.55	$	155.59	$	117.17	$	99.28
S&P 500	$	100.00	$	122.31	$	117.63	$	105.96	$	105.54	$	93.44	$	72.36
Russell 3000	$	100.00	$	122.05	$	117.41	$	105.71	$	103.43	$	93.80	$	71.97

	Initial Investment		Cumulative Total Return
			Q3-09		Q4-09		Q1-10(1)
EXXI	$	100.00	$	7.31	$	10.00	$	12.69
AMEX Oil Index	$	100.00	$	86.24	$	93.12	$	97.10
S&P 500	$	100.00	$	63.92	$	73.65	$	80.70
Russell 3000	$	100.00	$	12.69	$	74.05	$	81.40

(1) Through August 20, 2009.

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Item 6. Selected Financial Data

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

										Period from Inception July 25, 2005 Through June 30, 2006
	Year Ended June 30,
	2009			2008			2007
	(In Thousands, Except per Share Amounts)
Income Statement Data
Revenues	$	433,830		$	643,232		$	341,284		$	47,112
Depreciation, Depletion and Amortization (“DD&A”)		217,207			307,389			145,928			20,357
Impairment of Oil and Gas Properties		576,996			—			—			—
Operating Income (Loss)		(517,217	)		143,600			95,215			11,602
Other Income (Expense) – Net		(76,751	)		(101,857	)		(58,420	)		(2,933	)
Net Income (Loss)		(571,629	)		26,869			24,130			6,942
Basic Earnings (Loss) per Common Share	$	(3.95	)	$	0.31		$	0.29		$	0.14
Diluted Earnings (Loss) per Common Share	$	(3.95	)	$	0.30		$	0.29		$	0.12
Cash Flows Data
Provided by (Used in)
Operating Activities	$	224,906		$	366,052		$	270,783		$	12,068
Investing Activities
Acquisitions		—			(40,016	)		(717,618	)		(448,374	)
Investment in properties		(245,083	)		(308,578	)		(427,213	)		(19,703	)
Other		2,935			(296	)		1,955			(12,593	)
Total Investing Activities		(242,148	)		(348,890	)		(1,142,876	)		(480,670	)
Financing Activities		(62,795	)		132,016			829,488			530,991
Increase (Decrease) in Cash	$	(80,037	)	$	149,178		$	(42,605	)	$	62,389
Dividends Paid per Average Common Share	$	0.015			—			—			—

	June 30,
	2009		2008		2007		2006
	(In Thousands)
Balance Sheet Data
Total Assets	$	1,328,662	$	2,049,931	$	1,648,442	$	643,971
Long-term Debt Including Current Maturities		862,827		952,222		1,051,019		209,648
Stockholders’ Equity		127,500		374,585		397,126		352,709
Common Shares Outstanding		145,751		144,937		84,203		80,645

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Operating Highlights

										Period from Inception July 25, 2005 Through June 30, 2006
	Year Ended June 30,
	2009			2008			2007
	(In Thousands, Except per Unit Amounts)
Operating revenues
Crude oil sales	$	278,014		$	484,552		$	177,783		$	29,751
Natural gas sales		113,156			237,628			131,065			15,934
Hedge gain (loss)		42,660			(78,948	)		32,436			1,427
Total revenues		433,830			643,232			341,284			47,112
Percent of operating revenues from crude oil
Prior to hedge gain (loss)		71.1	%		67.1	%		57.6	%		67.3	%
Including hedge gain (loss)		67.5	%		61.6	%		56.8	%		62.0	%
Operating expenses
Lease operating expense
Insurance expense		19,188			18,218			12,670			144
Workover and maintenance		15,930			22,397			8,269			166
Direct lease operating expense		87,032			102,244			48,046			9,592
Total lease operating expense		122,150			142,859			68,985			9,902
Production taxes		5,450			8,686			3,595			84
Depreciation, depletion and amortization		217,207			307,389			145,928			20,357
Impairment of oil and gas properties		576,996			—			—			—
General and administrative		24,756			26,450			26,507			4,361
Other – net		4,488			14,248			1,054			806
Total operating expenses		951,047			499,632			246,069			35,510
Operating income (loss)	$	(517,217	)	$	143,600		$	95,215		$	11,602
Sales volumes per day
Natural gas (MMcf)		47.9			75.7			50.3			27.9
Crude oil (MBbls)		11.4			13.5			7.8			5.1
Total (MBOE)		19.3			26.2			16.2			9.7
Percent of sales volumes from crude oil		58.7	%		51.8	%		48.2	%		52.1	%
Average sales price
Natural gas per Mcf	$	6.48		$	8.57		$	7.13		$	6.48
Hedge gain per Mcf		1.60			0.34			0.90			0.86
Total natural gas per Mcf	$	8.08		$	8.91		$	8.03		$	7.34
Crude oil per Bbl	$	67.06		$	97.72		$	62.33		$	66.64
Hedge gain (loss) per Bbl		3.56			(17.82	)		5.60			(1.56	)
Total crude oil per Bbl	$	70.62		$	79.90		$	67.93		$	65.08
Total hedge gain (loss) per BOE	$	6.04		$	(8.24	)	$	5.48		$	1.67
Operating revenues per BOE	$	61.47		$	67.16		$	57.71		$	55.02
Operating expenses per BOE
Lease operating expense
Insurance expense		2.72			1.90			2.14			0.17
Workover and maintenance		2.26			2.34			1.40			0.19
Direct lease operating expense		12.33			10.68			8.12			11.20
Total lease operating expense		17.31			14.92			11.66			11.56
Production taxes		0.77			0.91			0.61			0.10
Impairment of oil and gas properties		81.75			—			—			—
Depreciation, depletion and amortization		30.78			32.09			24.68			23.78
General and administrative		3.51			2.76			4.48			5.09
Other – net		0.64			1.49			0.18			0.94
Total operating expenses		134.76			52.17			41.61			41.47
Operating income (loss) per BOE	$	(73.29	)	$	14.99		$	16.10		$	13.55

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Quarterly Highlights

	Quarter Ended
	June 30, 2009			Mar. 31, 2009			Dec. 31, 2008			Sept. 30, 2008			June 30, 2008
	(In Thousands Except for Unit Amounts)
Operating revenues
Crude oil sales	$	58,920		$	46,492		$	53,388		$	119,214		$	160,118
Natural gas sales		15,168			20,435			33,111			44,442			77,356
Hedge gain (loss)		27,010			39,209			20,353			(43,912	)		(58,712	)
Total revenues		101,098			106,136			106,852			119,744			178,762
Percent of operating revenues from crude oil
Prior to hedge gain (loss)		79.5	%		69.5	%		61.7	%		72.8	%		67.4	%
Including hedge gain (loss)		70.8	%		68.3	%		62.4	%		68.5	%		62.5	%
Operating expenses
Lease operating expense
Insurance expense		4,356			4,980			4,934			4,918			3,932
Workover and maintenance		4,622			341			7,094			3,873			6,741
Direct lease operating expense		15,646			19,643			25,536			26,207			29,108
Total lease operating expense		24,624			24,964			37,564			34,998			39,781
Production taxes		(51	)		1,587			1,878			2,036			3,699
Impairment of oil and gas properties		—			117,887			459,109			—			—
Depreciation, depletion and amortization		39,744			50,052			65,002			62,409			83,462
General and administrative		6,168			6,117			6,236			6,235			10,123
Other – net		3,852			7,643			(7,604	)		597			5,932
Total operating expenses		74,337			208,250			562,185			106,275			142,997
Operating income (loss)	$	26,761		$	(102,114	)	$	(455,333	)	$	13,469		$	35,765
Sales volumes per day
Natural gas (MMcf)		41.1			49.2			54.4			46.8			67.9
Crude oil (MBbls)		11.9			12.5			10.1			11.0			15.1
Total (MBOE)		18.7			20.7			19.2			18.8			26.4
Percent of sales volumes from crude oil		63.6	%		60.4	%		52.6	%		58.5	%		57.2	%
Average sales price
Natural gas per Mcf	$	4.06		$	4.62		$	6.62		$	10.33		$	12.52
Hedge gain (loss) per Mcf		3.85			2.98			1.41			(1.57	)		(1.66	)
Total natural gas per Mcf	$	7.91		$	7.60		$	8.03		$	8.76		$	10.86
Crude oil per Bbl	$	54.56		$	41.40		$	57.38		$	117.75		$	116.90
Hedge gain (loss) per Bbl		11.68			23.16			14.27			(36.70	)		(35.38	)
Total crude oil per Bbl	$	66.24		$	64.56		$	71.65		$	81.05		$	81.52
Total hedge gain (loss) per BOE	$	15.86		$	21.07		$	11.54		$	(25.39	)	$	(24.46	)
Operating revenues per BOE	$	59.36		$	57.04		$	60.57		$	69.23		$	74.49
Operating expenses per BOE
Lease operating expense
Insurance expense		2.56			2.68			2.79			2.84			1.64
Workover and maintenance		2.71			0.18			4.02			2.24			2.81
Direct lease operating expense		9.19			10.56			14.48			15.15			12.13
Total lease operating expense		14.46			13.42			21.29			20.23			16.58
Production taxes		(0.03	)		0.85			1.06			1.18			1.54
Impairment of oil and gas properties		—			63.35			260.26			—			—
Depreciation, depletion and amortization		23.34			26.90			36.85			36.08			34.78
General and administrative		3.62			3.29			3.54			3.60			4.22
Other – net		2.27			4.11			(4.31	)		0.35			2.47
Total operating expenses		43.66			111.92			318.69			61.44			59.59
Operating income (loss) per BOE	$	15.70		$	(54.88	)	$	(258.12	)	$	7.79		$	14.90

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

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

General

We are an independent oil and natural gas exploration and production company whose growth strategy emphasizes acquisitions, enhanced by our value-added organic drilling program. Our properties are primarily located in the U.S. Gulf of Mexico waters and the Gulf Coast onshore.

Our operations are geographically focused and we target acquisitions of oil and gas properties with which we can add value by increasing production and ultimate recovery of reserves, whether through exploitation or exploration, often using reprocessed seismic data to identify previously overlooked opportunities. For the year ended June 30, 2009, approximately 58 percent of our capital expenditures were associated with the exploitation of existing properties. During the past two years, we have sought to maintain our production at South Timbalier 21 and have gradually shifted our exploitation focus to the properties acquired from Pogo Producing on June 8, 2007. For the year ended June 30, 2009, production from those properties averaged 7.0 thousand barrels of oil equivalent per day (“MBOED”) and we spent approximately $50 million of capital on these acquired assets.

At June 30, 2009, our total proved reserves were 53.1 million barrels of oil equivalent (“MMBOE”) of which 58 percent were oil and 64 percent were classified as proved developed. We operated or had an interest in 274 producing wells on 148,784 net developed acres, including interests in 56 producing fields. All of our properties are located on the Gulf Coast and in the Gulf of Mexico, with approximately 78 percent of our proved reserves being offshore. This concentration facilitates our ability to manage the operated fields efficiently and our high number of wellbore locations provides diversification of our production and reserves. We believe operating our assets is key to our strategy; approximately 78 percent of our proved reserves are on properties operated by us. We have a seismic database covering approximately 3,100 square miles, primarily focused on our existing operations. This database has helped us identify at least 100 development and exploration opportunities. We believe the mature legacy fields on our acquired properties will lend themselves well to our aggressive exploitation strategy and expect to identify incremental exploration opportunities on the properties.

Initial Public Offering

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 AIM of the London Stock Exchange. On June 6, 2007, our common stock was admitted to the CREST electronic settlement system, which allows any interested party to trade our unrestricted common stock on AIM under the symbol “EXXI.” On August 1, 2007, our common stock was admitted for trading on NASDAQ under the symbol “EXXI.”

Acquisitions

Marlin.  On February 21, 2006, we entered into a definitive agreement with Marlin Energy, L.L.C. (“Marlin”) to acquire 100 percent of the membership interests in Marlin Energy Offshore, L.L.C. and Marlin Texas GP, L.L.C. and the limited partnership interests in Marlin Texas, L.P. (collectively, the “Oil and Gas Assets”) for total cash consideration of approximately $448.4 million,

Castex.  On June 7, 2006, we entered into a definitive agreement with a number of sellers to acquire certain oil and natural gas properties in Louisiana (the “Castex Acquisition”). We closed the Castex Acquisition on July 28, 2006. Our cash cost of the acquisition was approximately $311.2 million.

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Pogo Properties.  On June 8, 2007, we purchased certain oil and natural gas properties in the Gulf of Mexico (the “Pogo Properties”) from Pogo Producing Company (the “Pogo Acquisition”) for approximately $415.1 million.

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

Outlook

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. Multiple events during 2008 and to date in 2009 involving numerous financial institutions have effectively restricted current liquidity within the capital markets throughout the United States and around the world. Despite efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector, capital markets currently remain constrained. We expect that our ability to raise debt and equity at prices that are similar to offerings in recent years to be limited as long as the capital markets remain constrained.

During fiscal 2009, our stock price closed at a high of $6.59 on July 1, 2008 and our stock price declined to a closing low of $0.28 on March 3, 2009. We intend to move forward with our development drilling program when market conditions allow for an adequate return on the drilling investment and only when we have sufficient liquidity to do so. Maintaining adequate liquidity may involve the issuance of debt and equity at less attractive terms, could involve the sale of non-core assets and could require reductions in our capital spending. In the near-term we will focus on maximizing returns on existing assets by managing our costs and selectively deploying capital to improve existing production.

Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. As required by our revolving credit facility, we have mitigated this volatility through December 2011 by implementing a hedging program on a portion of our total anticipated production during this time frame. See Note 9 of Notes to Consolidated Financial Statements for a detailed discussion of our hedging program.

In August 2009, we reached a tentative agreement with our lead insurance underwriters on a $53.0 million global settlement of all outstanding claims related to last year’s hurricane damage (subject to documentation and to approval by the full insurer group). To the extent it is approved, the $53.0 million cash settlement is expected to be received during our fiscal second quarter, which ends December 31, 2009. The settlement amount is incremental to $27.9 million of reimbursements received through June 30, 2009 related to hurricane claims.

We face the challenge of natural gas and oil production declines. As a given well’s initial reservoir pressures are depleted, natural gas and oil production decreases, thus reducing our total reserves. We attempt to overcome this natural decline both by drilling on our properties and acquiring additional reserves. We will maintain our focus on controlling costs to add reserves through drilling and acquisitions, as well as controlling the corresponding costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability to timely obtain drilling permits and regulatory approvals and voluntary reductions in capital spending in a low commodity price environment. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of our production, which may have an adverse effect on our revenues. In accordance with our business strategy, we intend to invest the capital necessary to maintain our production at existing levels over the long-term provided that it is economical to do so based on the commodity price environment. However, we cannot be certain that we will be able to issue our debt and equity securities on

32

favorable terms, or at all, and we may be unable to refinance our revolving credit facility when it expires. Additionally, due to the significant decline in commodity prices, our borrowing base under our revolving credit facility may be re-determined such that it will not provide for the working capital necessary to fund our capital spending program.

Results of Operations

Year Ended June 30, 2009 Compared With the Year Ended June 30, 2008.

Our consolidated net loss was $571.6 million or $3.95 diluted loss per common share (“per share”) in fiscal 2009 principally as a result of the impairment of oil and gas properties due primarily to lower commodity prices and lower production volumes that were affected by Hurricanes Gustav and Ike. Below is a discussion of prices, volumes and revenue variances.

Price and Volume Variances

	Year Ended June 30,								Percent Decrease			Revenue Decrease
	2009		2008			Decrease
												(In Thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)	$	70.62	$	79.90		$	(9.28	)		(11.6	)%	$	(38,475	)
Natural gas sales prices (per Mcf)		8.08		8.91			(0.83	)		(9.3	)%		(14,502	)
Total price variance													(52,977	)
Volume Variance
Crude oil sales volumes (MBbls)		4,146		4,959			(813	)		(16.4	)%		(64,941	)
Natural gas sales volumes (MMcf)		17,472		27,716			(10,244	)		(37.0	)%		(91,484	)
BOE sales volumes (MBOE)		7,058		9,578			(2,520	)		(26.3	)%
Percent of BOE from crude oil		58.7		51.8	%
Total volume variance													(156,425	)
Total price and volume variance												$	(209,402	)

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

Revenue Variances

	Year Ended June 30,							Percent Decrease
	2009		2008		Decrease
	(In Thousands)
Crude oil	$	292,763	$	396,179	$	(103,416	)		(26.1	)%
Natural gas		141,067		247,053		(105,986	)		(42.9	)%
Total revenues	$	433,830	$	643,232	$	(209,402	)		(32.6	)%

Revenues

Our consolidated revenues decreased $209.4 million in fiscal 2009. Lower revenues were primarily due to lower crude oil and natural gas sales volumes that were significantly impacted by effects of Hurricanes Gustav and Ike coupled with the impact of lower commodity prices, resulting in decreased revenues of $156.4 million and $53.0 million, respectively. Revenue variances related to commodity prices and sales volumes are described below.

Price Variances

Commodity prices are one of our key drivers of earnings generation and net operating cash flow. Lower commodity prices reduced revenues $53.0 million in fiscal 2009. Average natural gas prices, including a $1.60 realized gain per Mcf related to hedging activities, decreased $0.83 per Mcf during fiscal 2009, resulting in decreased revenues of $14.5 million. Average crude oil prices, including a $3.56 realized gain per barrel

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related to hedging activities, decreased $9.28 per barrel in fiscal 2009, resulting in decreased revenues of $38.5 million. Commodity prices are affected by many factors that are outside of our control. Commodity prices we received during fiscal 2009 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time could result in reduced cash from operating activities, potentially causing us to expend less on our capital program. Lower spending on our capital program could result in a reduction of production volumes. We cannot accurately predict future commodity prices.

Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Lower sales volumes in fiscal 2009 resulted in decreased revenues of $156.4 million. Crude oil sales volumes decreased 813 MBbls in fiscal 2009, resulting in lower revenues of $64.9 million. Natural gas sales volumes decreased 10,244 MMcf in fiscal 2009, resulting in lower revenues of $91.5 million. The decrease in crude oil and natural gas sales volumes in fiscal 2009 was primarily due to the effects of Hurricanes Gustav and Ike.

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

Below is a discussion of costs and expenses and other (income) expense.

Costs and Expenses and Other (Income) Expense

	Year Ended June 30,												Increase (Decrease) Amount
	2009						2008
	Amount			Per BOE			Amount			Per BOE
	(In Thousands, Except per Unit Amounts)
Costs and expenses
Lease operating expense
Insurance expense	$	19,188		$	2.72		$	18,218		$	1.90		$	970
Workover and maintenance		15,930			2.26			22,397			2.34			(6,467	)
Direct lease operating expense		87,032			12.33			102,244			10.68			(15,212	)
Total lease operating expense		122,150			17.31			142,859			14.92			(20,709	)
Production taxes		5,450			0.77			8,686			0.91			(3,236	)
Impairment of oil and gas properties		576,996			81.75			—			—			576,996
DD&A		217,207			30.78			307,389			32.09			(90,182	)
Accretion of asset retirement obligation		14,635			2.07			8,176			0.85			6,459
General and administrative expense		24,756			3.51			26,450			2.76			(1,694	)
Loss (gain) on derivative financial instruments		(10,147	)		(1.43	)		6,072			0.64			(16,219	)
Total costs and expenses	$	951,047		$	134.76		$	499,632		$	52.17		$	451,415
Other (income) expense
Interest income	$	(7,498	)	$	(1.06	)	$	(1,403	)	$	(0.15	)	$	(6,095	)
Interest expense		84,249			11.93			103,260			10.78			(19,011	)
Total other (income) expense	$	76,751		$	10.87		$	101,857		$	10.63		$	(25,106	)

Costs and expenses increased $451.4 million in fiscal 2009. This increase in costs and expenses was primarily due to the $577.0 million impairment of oil and gas properties. Because of the significant decline in crude oil and natural gas prices, coupled with the impact of Hurricanes Gustav and Ike, we recognized a non-cash write-down of the net book value of our oil and gas properties of $117.9 million and $459.1 million in the third and second quarters of fiscal 2009, respectively. The write-downs were reduced by $179.9 million and $203.0 million pre-tax as a result of our hedging program in the third and second quarters of fiscal 2009, respectively. The impact of the impairment of oil and gas properties was partially offset by the items discussed below.

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DD&A expense decreased $90.2 million primarily due to lower production ($80.9 million) coupled with a lower DD&A rate ($9.3 million) as result of the write-down of oil and gas properties. Lease operating expense decreased $20.7 million in fiscal 2009 compared to fiscal 2008. This decrease was primarily due to lower well operating expenses stemming from the decrease in producing properties resulting from the hurricane damage noted above.

Accretion of asset retirement obligation increased $6.5 million as a result of the increase in plugged and abandoned properties related to our write-down.

The increase in gain on derivative financial instruments in fiscal 2009 compared to fiscal 2008 of $16.2 million is principally due to the turnaround related to the net price ineffectiveness of our hedged crude oil and natural gas contracts.

Production taxes decreased $3.2 million primarily as a result of lower crude oil and natural gas revenues as well as a decrease in total production.

Other (income) expense decreased $25.1 million in fiscal 2009. Interest income increased $6.1 million due primarily to higher interest bearing investments partially offset by lower interest rates. Interest expense decreased $19.0 million due to the repurchase of bonds and repayments of debt.

Income Tax Expense

Income tax expense decreased $37.2 million in fiscal 2009 compared to fiscal 2008, primarily due to a decrease in income before income taxes of $635.7 million, and the establishment of a valuation allowance against the net deferred U.S. tax assets. The effective income tax rate for fiscal 2009 decreased from fiscal 2008 from 35.6 percent to 3.8 percent.

Year Ended June 30, 2008 Compared With the Year Ended June 30, 2007.

Our consolidated net income increased to $26.9 million or $0.30 diluted earnings per common share (“per share”) in fiscal 2008 primarily due to higher commodity prices and higher production volumes. Below is a discussion of prices, volumes and revenue variances.

Price and Volume Variances

	Year Ended June 30,								Percent Increase			Revenue Increase
	2008			2007			Increase
												(In Thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)	$	79.90		$	67.93		$	11.97		17.6	%	$	59,359
Natural gas sales prices (per Mcf)		8.91			8.03			0.88		11.0	%		24,390
Total price variance													83,749
Volume Variance
Crude oil sales volumes (MBbls)		4,959			2,852			2,107		73.9	%		143,071
Natural gas sales volumes (MMcf)		27,716			18,370			9,346		50.9	%		75,128
BOE sales volumes (MBOE)		9,578			5,914			3,664		62.0	%
Percent of BOE from crude oil		51.8	%		48.2	%
Total volume variance													218,199
Total price and volume variance												$	301,948

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

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Revenue Variances

	Year Ended June 30,						Percent Increase
	2008		2007		Increase
	(In Thousands)
Crude oil	$	396,179	$	193,749	$	202,430		104.5	%
Natural gas		247,053		147,535		99,518		67.5	%
Total revenues	$	643,232	$	341,284	$	301,948		88.5	%

Revenues

Our consolidated revenues increased $301.9 million in fiscal 2008. Higher revenues were primarily due to higher commodity prices, a change in mix to a higher percentage of oil production and greater total volumes, resulting in increased revenues of $83.7 million and $218.2 million, respectively. Revenue variances related to commodity prices and sales volumes are described below.

Price Variances

Commodity prices are one of our key drivers of earnings generation and net operating cash flow. Higher commodity prices contributed $83.7 million to the increase in revenues in fiscal 2008. Average natural gas prices, including a $0.34 realized gain per Mcf related to hedging activities, increased $0.88 per Mcf during fiscal 2008, resulting in increased revenues of $24.4 million. Average crude oil prices, including a $(17.82) realized loss per barrel related to hedging activities, increased $11.97 per barrel in fiscal 2008, resulting in increased revenues of $59.4 million. Commodity prices are affected by many factors that are outside of our control. Therefore, commodity prices we received during fiscal 2008 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time could result in reduced cash from operating activities, potentially causing us to expend less on our capital program. Lower spending on our capital program could result in a reduction of the amount of production volumes we are able to produce. We cannot accurately predict future commodity prices.

Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Higher sales volumes in fiscal 2008 resulted in increased revenues of $218.2 million. Crude oil sales volumes increased 2,107 MBbls in fiscal 2008, resulting in increased revenues of $143.1 million. Natural gas sales volumes increased 9,346 MMcf in fiscal 2008, resulting in increased revenues of $75.1 million. The increase in crude oil and natural gas sales volumes in fiscal 2008 was primarily due to our acquisitions and our exploration and development programs.

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

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Below is a discussion of costs and expenses and other (income) expense.

Costs and Expenses and Other (Income) Expense

	Year Ended June 30,												Increase (Decrease) Amount
	2008						2007
	Amount			Per BOE			Amount			Per BOE
	(In Thousands, Except per Unit Amounts)
Costs and expenses
Lease operating expense
Insurance expense	$	18,218		$	1.90		$	12,670		$	2.14		$	5,548
Workover and maintenance		22,397			2.34			8,269			1.40			14,128
Direct lease operating expense		102,244			10.68			48,046			8.12			54,198
Total lease operating expense		142,859			14.92			68,985			11.66			73,874
Production taxes		8,686			0.91			3,595			0.61			5,091
DD&A		307,389			32.09			145,928			24.68			161,461
Accretion of asset retirement obligation		8,176			0.85			3,991			0.68			4,185
General and administrative expense		26,450			2.76			26,507			4.48			(57	)
Loss (gain) on derivative financial instruments		6,072			0.64			(2,937	)		(0.50	)		9,009
Total costs and expenses	$	499,632		$	52.17		$	246,069		$	41.61		$	253,563
Other (income) expense
Interest income	$	(1,403	)	$	(0.15	)	$	(1,910	)	$	(0.32	)	$	507
Interest expense		103,260			10.78			60,330			10.20			42,930
Total other (income) expense	$	101,857		$	10.63		$	58,420		$	9.88		$	43,437

Costs and expenses increased $253.6 million in fiscal 2008. This increase in costs and expenses was primarily due to the items discussed below.

DD&A expense increased $161.5 million primarily due to increased production from acquisitions and drilling ($90.4 million), coupled with a higher DD&A rate ($71.1 million). Lease operating expense increased $73.9 million in fiscal 2008 compared to fiscal 2007. This increase is primarily due to higher well operating expenses stemming from the increase in properties resulting from acquisitions as well as an increase in general operating costs, which include direct expenses incurred to operate our wells and equipment on producing leases. We typically incur higher direct operating costs associated with operating wells that produce higher percentages of oil versus natural gas. As we increased our percentage production of oil during fiscal 2008, partially as a result of the acquisition of the properties from Pogo Producing, our lease operating expenses per BOE have increased. In addition to increased costs per BOE due to a change in mix of production, well operating expenses were higher in general due to increased fuel, chemical and electricity expenses and higher repair and maintenance expenses. The higher workover activity and higher windstorm insurance is also primarily due to an increase in producing leases from acquisitions.

Production taxes increased $5.1 million primarily as a result of higher crude oil and natural gas revenues as well as an increase in total production.

Other (income) expense increased $43.4 million in fiscal 2008. This increase was primarily due to the items discussed below.

Interest income decreased $0.5 million due primarily to lower interest rates. Interest expense increased $42.9 million due to the additional borrowings required to fund our acquisition and capital expenditure programs. On a per unit of production basis, interest expense increased 5.7 percent, from $10.20/BOE to $10.78/BOE.

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Income Tax Expense

Income tax expense increased $2.2 million in fiscal 2008 compared to fiscal 2007, primarily due to an increase in income before income taxes of $4.9 million and to an increase in the effective income tax rate from 34.4 percent to 35.6 percent.

Liquidity

Overview

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

• drilling and completing new natural gas and oil wells;

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

• constructing and installing new production infrastructure;

• acquiring additional reserves and producing properties;

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

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

• plugging and abandoning depleted or uneconomic wells; and

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

We have incurred substantial indebtedness in connection with our acquisitions, including the $750 million senior notes offering we completed on June 8, 2007 to fund the Pogo Acquisition and to repay our second lien revolving credit facility. At June 30, 2009, we had $862.8 million of indebtedness outstanding, consisting of $624.0 million in our high yield facility, $234.5 million under our first lien revolving credit facility, $3.9 million in put financings and $0.4 million in capital lease obligations. This debt position is partially offset on a net basis by $88.9 million of cash and cash equivalents on hand at June 30, 2009. As of September 4, we had no availability for borrowing under our revolving credit facility.

We are currently considering various alternatives to enhance our liquidity and to repay indebtedness under our revolving credit facility, including engaging in discussions with a limited number of qualified institutional buyers about a possible issuance of between $50 million and $89 million of debt securities and shares of common stock for cash in a private placement. A significant portion of the proceeds from such private placement, if completed, would be used to repay indebtedness under our revolving credit facility. Any such offering would be conditioned upon successful completion of an exchange offer of newly issued 16% second lien junior secured notes due 2014 for up to $360 million outstanding principal amount of our 10% senior notes due 2013. No assurance can be given that we will be able to successfully complete any such transactions or the ultimate terms or timing.

Disruption to Functioning of Capital Markets

Multiple events during 2008 and to date in 2009 involving numerous financial institutions have effectively restricted current liquidity within the capital markets throughout the United States and around the world. Despite efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector, capital markets currently remain constrained. We expect that our ability to issue debt and equity on favorable terms will be limited as long as the capital markets remain constrained. Our development drilling program is impacted by conditions allowing for an adequate return on a drilling investment and when we have sufficient liquidity. The benefits expected to accrue to our stockholders from our exploration and development activities may be muted by substantial cost of capital increases during this period.

Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. For example, the NYMEX crude oil

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spot price per barrel for the period between January 1, 2009 and July 31, 2009 ranged from a high of $72.68 to a low of $33.98 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2009 to July 31, 2009 ranged from a high of $6.072 to a low of $3.253. 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.

During fiscal 2009, our stock price closed at a high of $6.59 on July 1, 2008 and our stock price declined to a closing low of $0.28 on March 3, 2009. We intend to move forward with our development drilling program when market conditions allow for an adequate return on the drilling investment and only when we have sufficient liquidity to do so. Maintaining adequate liquidity may involve the issuance of debt and equity at less attractive terms, could involve the sale of non-core assets and could require reductions in our capital spending. In the near-term we will focus on maximizing returns on existing assets by managing our costs and selectively deploying capital to improve existing production.

Cash Flows From Operations

Cash flows from operations were used primarily to fund exploration and development expenditures during the year ended June 30, 2009. At June 30, 2009 we had a working capital deficit of $4.6 million. Net cash provided by operating activities in fiscal 2009 decreased $141.1 million and $45.9 million from fiscal 2008 and from fiscal 2007, respectively. The decrease in fiscal 2009 as compared to fiscal 2008 is primarily due to lower production volumes and lower commodity prices (including hedging activities) partially offset by lower costs and expenses, excluding non-cash expenses. Key drivers of net operating cash flows are commodity prices, production volumes and costs and expenses. Average natural gas prices decreased 9.3 percent in fiscal 2009 from fiscal 2008. Average crude oil prices decreased 11.6 percent in fiscal 2009 from fiscal 2008. In fiscal 2009, natural gas volumes and crude oil volumes decreased 37.0 percent and 16.4 percent from fiscal 2008 period, respectively.

The decrease in net cash provided by operating activities resulting from lower commodity prices and lower production volumes was partially offset by lower costs and expenses. In fiscal 2009, costs and expenses that affect net operating cash provided by operating activities primarily include lease operating expense, production taxes and general and administrative expense. These costs and expenses decreased $25.6 million from fiscal 2008. Lease operating expense represented the largest decrease in these costs. Lease operating expense includes well operating expenses, which are expenses incurred to operate our wells and equipment on operating leases.

Generally, producing natural gas and crude oil reservoirs have declining production rates. Production rates are impacted by numerous factors, including but not limited to, geological, geophysical and engineering matters, production curtailments and restrictions, weather, market demands and our ability to replace depleting reserves. Our inability to adequately replace reserves could result in a decline in production volumes, one of the key drivers of generating net operating cash flows. For the fiscal year ended June 30, 2009, our reserve replacement ratio, which is calculated by dividing additions to proved reserves by total production, was 90 percent. Results for any year are a function of the success of our drilling program and acquisitions. While program results are difficult to predict, our current drilling inventory provides us opportunities to replace our production in fiscal 2010.

Investing Activities — Acquisitions and Capital Expenditures

Our investments in properties, including acquisitions, were $245.1 million, $348.6 million and $1,144.8 million for the years ended June 30, 2009, 2008 and 2007, respectively. The decrease in cash used in investing activities in comparing fiscal 2009 to fiscal 2008 and to fiscal 2007 is primarily due to acquisitions in the prior fiscal periods.

Excluding any potential acquisitions and hurricane related abandonment costs, we currently anticipate a capital budget for 2010 of approximately $85 million. We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, and future acquisitions from cash on hand, cash flows from our operations and borrowings under our credit facility. If an acquisition opportunity arises, we may also access public markets to issue additional debt and/or equity securities. As of September 4, 2009, we had no availability for borrowing under our revolving credit facility. Our current borrowing base is

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$240 million. Our next borrowing base redetermination is scheduled for the fall of 2009 utilizing our June 30, 2009 reserve report. Based on the current commodity price environment, banks may have lowered their internal projections of future natural gas and oil prices which may decrease the borrowing base and thus decrease the amount available to be borrowed under our revolving credit facility. If commodity prices continue to decline and banks continue to lower their internal projections of natural gas and oil prices, it is possible that we will be subject to decreases in our borrowing base availability in the future. We anticipate that our cash flow from operations and available borrowing capacity under our revolving credit facility will exceed our planned capital expenditures and other cash requirements for the year ended June 30, 2010. However, future cash flows are subject to a number of variables, including the level of natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Cash used by financing activities was $62.8 million for the year ended June 30, 2009, compared to cash provided by financing activities of $132.0 million for the year ended June 30, 2008. During the year ended June 30, 2009, total proceeds from borrowings under our revolving credit facility, net of repayments were $35.6 million which were used to partially offset the purchase bonds of $90.9 million. During the year ended June 30, 2008, total net payments under our revolving credit facility were $105.6 million, which were principally made from the proceeds of our exchange of warrants of $237.8 million.

Available Credit

Credit markets in the United States and around the world remain constrained due to a lack of liquidity and confidence in a number of financial institutions. Investors continue to seek perceived safe investments in securities of the United States government rather than individual entities. We may experience difficulty accessing the long-term credit markets due to prevailing market conditions. Additionally, existing constraints in the credit markets may increase the rates we are charged for utilizing these markets. Notwithstanding the continuing weakness in the United States credit markets, we expect that our available liquidity is sufficient to meet our operating and capital requirements into 2010.

First Lien Revolver

Our first lien revolver was amended and restated on June 8, 2007. This facility was entered into by our subsidiary, EGC. This facility has a face value of $700 million and matures on June 8, 2011. The credit facility bore interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 1.50 percent to 2.25 percent or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.50 percent to 1.25 percent. However, if an additional equity contribution in an amount of at least $50 million is made by us to EGC, all of the margins above will be subject to a 0.25 percent reduction. This equity investment was made in June 2008. The credit facility is secured by mortgages on at least 85 percent of the value of our proved reserves. Our initial borrowing base under the facility was $425 million.

On November 19, 2007, the credit facility was further amended. The amendment, among other things, increased the borrowing base to $450 million and modified the commodity hedge limitations and minimum liquidity during certain periods. We incurred $0.7 million to amend the first lien revolver including $0.5 million associated with syndicating the credit facility.

On December 9, 2008, the credit facility was again amended. The amendment, among other things, reduced the borrowing base to $400 million. The amendment provides protection to other lenders should any bank in the syndicate fail to fund their share of the revolver and other provisions which effectively reduce the available borrowing base to $380 million and carves out certain derivative contracts from the hedge limits contained in the revolver.

On April 6, 2009 the credit facility was again amended. The amendment, among other things, reduced the borrowing base to $240 million, amended the financial covenants related to the total leverage ratio to 4.5 to 1.0 commencing with the quarter ended June 30, 2009 and added a secured debt ratio not to exceed 2.5 to 1.0 beginning with the quarter ended June 30, 2009. The amendment also modified the interest rates payable under the facility and pledged the EGC bonds held by us as security.

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Our first lien revolving credit facility requires us to maintain certain financial covenants. Specifically, EGC may not permit its total leverage ratio to be more than 4.5 to 1.0 with certain reductions in this ratio over time (which was amended on April 6, 2009), our interest rate coverage ratio to be less than 3.0 to 1.0, a secured debt ratio to be more than 2.5 to 1.0, or our current ratio (in each case as defined in our first lien revolving credit facility) to be less than 1.0 to 1.0, in each case, as of the end of each fiscal quarter. In addition, we are subject to various covenants including those limiting dividends and other payments, making certain investments, margin, consolidating, modifying certain agreements, transactions with affiliates, the incurrence of debt, changes in control, asset sales, liens on properties, sale leaseback transactions, entering into certain leases, the allowance of gas imbalances, take or pay or other prepayments, entering into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr., Steven A. Weyel and David West Griffin in their current executive positions, subject to certain exceptions in the event of death or disability to one of these individuals.

The first lien revolving credit facility also contains customary events of default, including, but not limited to non-payment of principal when due, non-payment of interest or fees and other amounts after a grace period, failure of any representation or warranty to be true in all material respects when made or deemed made, defaults under other debt instruments (including the indenture governing the notes), commencement of a bankruptcy or similar proceeding by or on behalf of us or a guarantor, judgments against us or a guarantor, the institution by us to terminate a pension plan or other ERISA events, any change in control, loss of liens, failure to meet financial ratios, and violations of other covenants subject, in certain cases, to a grace period. As of June 30, 2009, we are in compliance with all covenants.

High Yield Facility

On June 8, 2007 our subsidiary, EGC, completed a $750 million private offering of 10 percent Senior Notes due 2013 (“Old Notes”). As part of the private offering EGC agreed to use its best efforts to complete an exchange offer, which it completed on October 16, 2007. In the exchange offer, the Old Notes were exchanged for $750 million of 10 percent Senior Notes due 2013 that have been registered under the Securities Act of 1933 (“New Notes”), with terms substantially the same as the Old Notes. All of the issued and outstanding Old Notes were exchanged for New Notes. We did not receive any cash proceeds from the exchange offer.

The notes are guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We have the right to redeem the new notes under various circumstances and are required to make an offer to repurchase the new notes upon a change of control and from the net proceeds of asset sales under specified circumstances.

We and our restricted subsidiaries are subject to certain negative covenants under the indenture governing the New Notes. The indenture limits our ability to, among other things:

• incur or assume additional debt or provide guarantees in respect of obligations of other persons;

• issue redeemable stock and preferred stock;

• pay dividends or distributions or redeem or repurchase capital stock;

• prepay, redeem or repurchase debt;

• make loans and investments;

• incur certain liens;

• impose limitations on dividends, loans or asset transfers from our subsidiaries;

• sell or otherwise dispose of assets, including capital stock of subsidiaries;

• consolidate or merge with or into, or sell substantially all of our assets to, another person;

• enter into transactions with affiliates; and

• impair the security interest in the collateral securing the New Notes.

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Put Premium Financing

We finance puts that we purchase with our hedge providers. Substantially all of our hedges are done with members of our bank groups. Put financing is accounted for as debt and this indebtedness is pari pasu with borrowings under the first lien revolving credit facility. The hedge financing is structured to mature when the put settles so that we realize the value net of hedge financing. As of June 30, 2009 and June 30, 2008, our outstanding hedge financing totaled $3.9 million and $9.7 million, respectively.

U.S. Minerals Management Service

For offshore operations, lessees must comply with the U.S. Minerals Management Service’s (“MMS”) regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Shelf and removal of facilities. To cover the various obligations of lessees on the U.S. Outer Continental Shelf of the Gulf of Mexico, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. We are currently reviewing whether we are exempt from the supplemental bonding requirements of the MMS. The cost of these bonds or other surety could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. Such letters of credit would likely be issued under our first lien credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. The cost of compliance with these supplemental bonding requirements could materially and adversely affect our financial condition, cash flows and results of operations.

Commodity Prices

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

Potential Acquisitions

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

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Future Commitments

The table below provides estimates of the timing of future payments that, as of June 30, 2009, we are obligated to make. We expect to fund these contractual obligations with cash on hand and cash generated from operations.

	Payments Due by Period
	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
	(In Thousands)
Contractual Obligations
Total debt(1)	$	862,827	$	4,107	$	234,720	$	624,000	$	—
Interest on long-term debt(1)		267,352		73,229		134,629		59,494		—
Operating leases(2)		11,457		1,349		2,699		2,699		4,710
Performance bonds(2)		11,825		11,825		—		—		—
Drilling rig commitments(2)		2,800		2,800		—		—		—
Letters of credit(2)		1,100		1,100		—		—		—
Total contractual obligations		1,157,361		94,410		372,048		686,193		4,710
Other Obligations
Asset retirement obligations(3)		309,886		87,366		40,135		28,892		153,493
Total obligations	$	1,467,247	$	181,776	$	412,183	$	715,085	$	158,203

(1) See Note 6 of Notes to Consolidated Financial Statements for details of total debt.

(2) See Note 16 of Notes to Consolidated Financial Statements for discussion of these commitments.

(3) See Note 8 of Notes to Consolidated Financial Statements for details of asset retirement obligations (the obligations reflected above are undiscounted).

Critical Accounting Policies

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

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established by the SEC, the estimation of reserves requires the engineers to make a number of assumptions based on professional judgment. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions in reserve quantities. Reserve revisions will inherently lead to adjustments of DD&A rates. We cannot predict the types of reserve revisions that will be required in future periods.

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

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 unevaluated 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 also allocate a portion of our acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

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 are difficult to predict. As discussed in note 3 of notes to the consolidated financial statements, we recorded a write-down to our oil and gas properties in the second and third quarters of fiscal 2009. At June 30, 2009, 2008 and 2007, a 10 percent decrease in oil and gas prices would not impact the results of 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 the Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. The present value of the future costs are added to the capitalized cost of our oil and gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that are difficult to predict.

In August 2008, Hurricane Gustav and in September 2008 Hurricane Ike damaged certain of our facilities in the Gulf of Mexico which increased our abandonment costs and changed the timing of the estimated abandonment.

Derivative Instruments.  We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Such derivatives are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended. Gains or losses resulting from transactions designated as hedges, recorded at market value, are deferred and recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating

44

income in our consolidated statement of income as the physical production hedged by the contracts is delivered. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings.

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

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

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

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

The following table summarizes the sensitivity of our derivative contracts to changes in oil and gas prices:

	June 30, 2009						June 30, 2008						June 30, 2007
	Oil (Bbl)			Gas (MMbtu)			Oil (Bbl)			Gas (MMbtu)			Oil (Bbl)			Gas (MMbtu)
Average prices used in determining fair value	$	73.86		$	5.70		$	140.28		$	12.62		$	71.94		$	8.23
Decrease in fair value of derivative contracts resulting from a 10 percent increase in oil or natural gas prices (in thousands)(1)(2):	$	(19,469	)	$	(9,734	)	$	(81,300	)	$	(33,400	)	$	(30,500	)	$	(19,100	)

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

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

Net income would have increased (decreased) for the years ended June 30, 2009, 2008 and 2007 by $323.7 million, $(286.0) million and $7.8 million, respectively, if our crude oil and natural gas hedges did not qualify as cash flow hedges under SFAS No. 133.

Income Taxes.  We account for income taxes in accordance with SFAS No. 109 Accounting for Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the

45

equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion.

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

We adopted the provisions of FIN 48 and applied the guidance of FIN 48-1 as of July 1, 2007. As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of FIN 48 or have any gross unrecognized tax benefit. At June 30, 2009, we did not have any FIN 48 liability or gross recognized tax benefit.

Share-Based Compensation.  As of July 1, 2007, we adopted SFAS No. 123 (revised 2004) (“SFAS No. 123(R)”), Share-Based Payment. The adoption had no impact on our financial statements. In accordance with SFAS No. 123(R), compensation cost is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award.

New Accounting Standards

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

Modernization of Oil and Gas Reporting.  In December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which is effective January 1, 2010 for reporting 2009 oil and gas reserve information. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure also requires companies to include nontraditional resources such as oil sands, shale, coalbeds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently the SEC requires that reserve volumes are determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the prior twelve-month period rather than year-end prices. The twelve-month average price will also be used for purposes of calculating future net cash flows from proved oil and gas reserves for the SEC full cost ceiling limitations, and the results will not be subject to a single day pricing mechanism. Although the Financial Accounting Standards Board (“FASB”) currently requires the price on the last day of the reporting period to be used for accounting purposes, the FASB has added it to their agenda to conform with the SEC. The new requirements also will allow companies to disclose their probable and possible reserves to investors and will require companies to report the independence and qualifications of their reserve preparer or auditor. We will adopt the provisions of the release for our June 30, 2010 Annual Report on Form 10-K. We are currently evaluating the impact of the release.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.  In April 2009, the FASB issued FASB Staff Position (“FSP”) FAS 157-4 Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”) and FSP FAS 107-1 and APB 28-1 Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). These FSPs are effective for interim reporting periods ending after June 15, 2009, with early adoption permitted; however, early adoption requires that the FSPs are adopted concurrently.

FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157, Fair Value Measurements (“SFAS 157”), when the volume and level of activity for the asset or liability have significantly decreased, as well as guidance for identifying circumstances that indicate a transaction is not orderly. This FSP emphasizes that even if there has been a significant decrease in the volume and level of

46

activity for the asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date under current market conditions.

FSP FAS 107-1 and APB 28-1 amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods.

The adoption of these FSP’s did not have an impact on our consolidated financial position, results of operations or cash flows.

Subsequent Events.  In May 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS 165”), which establishes principles and requirements for subsequent events. This statement defines the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, and the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements. SFAS 165 also sets forth the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 is effective for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 did not have an impact on our consolidated financial position, results of operations or cash flows. We evaluate events and transactions that occur after the balance date but before the financial statements are issued. We evaluated such events and transactions through September 4, 2009, when the financial statements were electronically filed with the SEC.

Amendments to FASB Interpretation (“FIN”) No. 46(R) (“FIN 46(R)”).  In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation (“FIN”) No. 46(R) (“FIN 46(R)”), (“SFAS 167”). The amendments include: (1) the elimination of the exemption for qualifying special purpose entities, (2) a new approach for determining who should consolidate a variable-interest entity, and (3) changes to when it is necessary to reassess who should consolidate a variable-interest entity. This statement is effective for fiscal years beginning after November 15, 2009, and for interim periods within that first annual reporting period. We are currently evaluating the impact of this standard.

Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.  In June 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. Emerging Issues Task Force (“EITF”) 03-6-1 (“FSP 03-6-1”), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share under the two-class method described in SFAS No. 128, Earnings Per Share. FSP 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years and will require all earnings per share data presented for prior-periods to be restated retrospectively. We currently do not anticipate that FSP 03-6-1 will have a material impact on our earnings per share data for fiscal year 2010 or on earnings per share data for any prior periods presented.

Accounting for Business Combinations.  In December 2007, the FASB issued SFAS No. 141R, Business Combinations (“SFAS 141R”), which replaces SFAS No. 141, Business Combinations. SFAS 141R establishes principles and requirements for determining how an enterprise recognizes and measures the fair value of certain assets and liabilities acquired in a business combination, including non-controlling interests, contingent consideration, and certain acquired contingencies. SFAS 141R also requires acquisition-related transaction expenses and restructuring costs be expensed as incurred rather than capitalized as a component of the business combination. SFAS 141R will be applicable prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS 141R would have an impact on accounting for any businesses acquired after the date of adoption, which is July 1, 2009 for the Company.

47

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market-Sensitive Instruments and Risk Management

Market risk is the potential loss arising from adverse changes in market rates and prices, such as commodity prices and interest rates. Our primary market risk exposures are commodity price risk, principally natural gas and crude oil. We also have had market risk exposure related to changes in interest rates. These exposures are discussed in detail below.

Commodity Price Risk

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

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

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

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

Disclosure of Limitations

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

Interest Rate Risk

On June 26, 2006, we entered into an interest rate costless collar to mitigate the risk of loss due to changes in interest rates. The dollar amount hedged was $75 million with the interest rate collar being 5.45 percent to 5.75 percent. At June 30, 2009, 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 $3.5 million.

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

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Item 8. Financial Statements and Supplementary Financial Information

	Page
Management’s Report on Internal Control over Financial Reporting		50
Reports of Independent Registered Public Accounting Firm		51
Consolidated Financial Statements
Consolidated Balance Sheets		53
Consolidated Statements of Operations		54
Consolidated Statement of Stockholders’ Equity		55
Consolidated Statements of Cash Flows		56
Notes to Consolidated Financial Statements		57

49

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management, including our Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of our internal control over financial reporting as of June 30, 2009. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, our management has concluded that, as of June 30, 2009, our internal control over financial reporting was effective based on those criteria.

UHY LLP, the independent registered public accounting firm that audited the consolidated financial statements included in this Annual Report on Form 10-K, has also audited the effectiveness of internal control over financial reporting as of June 30, 2009 as stated in their report that appears on page 52.

50

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Energy XXI (Bermuda) Limited (a Bermuda Corporation) and subsidiaries (the “Company”) as of June 30, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three fiscal years in the period ended June 30, 2009. The Company’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide 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 (Bermuda) Limited and subsidiaries as of June 30, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three fiscal years in the period ended June 30, 2009, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Energy XXI (Bermuda) Limited and subsidiaries’ internal control over financial reporting as of June 30, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated September 4, 2009 expressed an unqualified opinion on the effective operation of internal control over financial reporting.

/s/ UHY LLP

Houston, Texas
September 4, 2009

51

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited Energy XXI (Bermuda) Limited and subsidiaries’ (the “Company”) internal control over financial reporting as of June 30, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Energy XXI (Bermuda) Limited and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of June 30, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Energy XXI (Bermuda) Limited and subsidiaries as of June 30, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three fiscal years in the period ended June 30, 2009, and our report dated September 4, 2009 expressed an unqualified opinion on those consolidated financial statements.

/s/ UHY LLP

Houston, Texas
September 4, 2009

52

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

	June 30,
	2009			2008
ASSETS
Current Assets
Cash and cash equivalents	$	88,925		$	168,962
Accounts receivable
Oil and natural gas sales		40,087			116,678
Joint interest billings		17,624			21,322
Insurance and other		2,562			4,896
Prepaid expenses and other current assets		16,318			14,662
Royalty deposit		1,746			4,548
Deferred income taxes		—			88,198
Derivative financial instruments		31,404			2,179
Total Current Assets		198,666			421,445
Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment
Oil and natural gas properties – full cost method of accounting		1,102,596			1,561,276
Other property and equipment		9,149			10,020
Total Property and Equipment		1,111,745			1,571,296
Other Assets
Derivative financial instruments		3,838			3,747
Deferred income taxes		—			36,055
Debt issuance costs, net of accumulated amortization		14,413			17,388
Total Other Assets		18,251			57,190
Total Assets	$	1,328,662		$	2,049,931
LIABILITIES
Current Liabilities
Accounts payable	$	81,025		$	106,751
Accrued liabilities		36,180			82,152
Asset retirement obligations		66,244			16,717
Derivative financial instruments		15,732			245,626
Current maturities of long-term debt		4,107			7,250
Total Current Liabilities		203,288			458,496
Long-term debt, less current maturities		858,720			944,972
Deferred income taxes		26,889			—
Asset retirement obligations		77,955			81,097
Derivative financial instruments		4,818			190,781
Other liabilities		29,492			—
Total Liabilities		1,201,162			1,675,346
Commitments and Contingencies (Note 16)
Stockholders’ Equity
Preferred stock, $0.01 par value, 2,500,000 shares authorized and no shares issued at June 30, 2009 and 2008		—			—
Common stock, $0.001 par value, 400,000,000 shares authorized and 146,415,258 and 145,299,675 shares issued and 145,750,584 and 144,937,119 shares outstanding at June 30, 2009 and 2008, respectively		146			145
Additional paid-in capital		604,724			601,509
Retained earnings (deficit)		(515,867	)		57,941
Accumulated other comprehensive income (loss), net of income tax expense (benefit)		38,497			(285,010	)
Total Stockholders’ Equity		127,500			374,585
Total Liabilities and Stockholders’ Equity	$	1,328,662		$	2,049,931

 
 
See Accompanying Notes to Consolidated Financial Statements

53

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except per Share Information)

	Year Ended June 30,
	2009			2008			2007
Revenues
Crude oil sales	$	292,763		$	396,179		$	193,749
Natural gas sales		141,067			247,053			147,535
Total Revenues		433,830			643,232			341,284
Costs and Expenses
Lease operating expense		122,150			142,859			68,985
Production taxes		5,450			8,686			3,595
Impairment of oil and gas properties		576,996			—			—
Depreciation, depletion and amortization		217,207			307,389			145,928
Accretion of asset retirement obligations		14,635			8,176			3,991
General and administrative expense		24,756			26,450			26,507
Loss (gain) on derivative financial instruments		(10,147	)		6,072			(2,937	)
Total Costs and Expenses		951,047			499,632			246,069
Operating Income (Loss)		(517,217	)		143,600			95,215
Other Income (Expense)
Interest income		7,498			1,403			1,910
Interest expense		(84,249	)		(103,260	)		(60,330	)
Total Other Income (Expense)		(76,751	)		(101,857	)		(58,420	)
Income (Loss) Before Income Taxes		(593,968	)		41,743			36,795
Income Tax Expense (Benefit)		(22,339	)		14,874			12,665
Net Income (Loss)	$	(571,629	)	$	26,869		$	24,130
Earnings (Loss) per Share
Basic	$	(3.95	)	$	0.31		$	0.29
Diluted	$	(3.95	)	$	0.30		$	0.29
Weighted Average Number of Common Shares Outstanding
Basic		144,593			85,809			83,959
Diluted		144,593			90,271			83,959

 
 
See Accompanying Notes to Consolidated Financial Statements

54

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

					Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
	Common Stock
	Shares		Value
Balance, June 30, 2006		80,645	$	81	$	350,238		$	6,942		$	(4,552	)	$	352,709
Common stock issued		3,558		3		14,037									14,040
Warrants repurchased						(1,069	)								(1,069	)
Comprehensive income:
Net income									24,130						24,130
Unrealized gain on derivative financial instruments, net of income tax expense												7,316			7,316
Total comprehensive income															31,446
Balance, June 30, 2007		84,203		84		363,206			31,072			2,764			397,126
Common stock issued		16				568									568
Restricted shares issued		293
Warrants exercised		259				1,292									1,292
Warrant exchange		60,529		61		236,463									236,524
Warrants repurchased						(20	)								(20	)
Comprehensive income (loss):
Net income									26,869						26,869
Unrealized loss on derivative financial instruments, net of income tax benefit												(287,774	)		(287,774	)
Total comprehensive loss															(260,905	)
Balance, June 30, 2008		145,300		145		601,509			57,941			(285,010	)		374,585
Common stock issued		503		1		589									590
Restricted shares issued		612				2,626									2,626
Dividends									(2,179	)					(2,179	)
Comprehensive income (loss):
Net loss									(571,629	)					(571,629	)
Unrealized gain on derivative financial instruments, net of income tax benefit												323,507			323,507
Total comprehensive loss															(248,122	)
Balance, June 30, 2009		146,415	$	146	$	604,724		$	(515,867	)	$	38,497		$	127,500

 
 
See Accompanying Notes to Consolidated Financial Statements

55

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

	Year Ended June 30,
	2009			2008			2007
Cash Flows From Operating Activities
Net income (loss)	$	(571,629	)	$	26,869		$	24,130
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		217,207			307,389			145,928
Impairment of oil and gas properties		576,996			—			—
Deferred income tax expense (benefit)		(23,055	)		14,870			13,530
Change in derivative financial instruments
Proceeds from sale of derivative instruments		66,480			—			—
Other – net		(19,549	)		1,086			11,759
Accretion of asset retirement obligations		14,635			8,176			3,991
Amortization of deferred gain on debt		(5,620	)		—			—
Amortization and write-off of debt issuance costs		5,245			4,273			7,045
Common stock issued for Directors’ compensation and stock option expense		4,760			67			—
Changes in operating assets and liabilities
Accounts receivable		91,273			(66,341	)		16,458
Prepaid expenses and other current assets		1,146			4,835			(12,670	)
Settlements of asset retirement obligations		(25,421	)		(21,500	)		(4,614	)
Accounts payable and accrued liabilities		(107,562	)		86,328			65,226
Net Cash Provided by Operating Activities		224,906			366,052			270,783
Cash Flows from Investing Activities
Investment in properties		(245,083	)		(308,578	)		(427,213	)
Acquisitions		—			(40,016	)		(717,618	)
Proceeds from the sale of properties		3,233			—			1,400
Other		(298	)		(296	)		555
Net Cash Used in Investing Activities		(242,148	)		(348,890	)		(1,142,876	)
Cash Flows from Financing Activities
Proceeds from the issuance of common stock		—			501			14,040
Dividends to shareholders		(2,179	)
Proceeds from long-term debt		270,794			310,135			1,199,444
Proceeds from exchange of warrants		—			237,796			—
Payments on long-term debt		(236,707	)		(415,733	)		(358,574	)
Purchase of bonds		(90,888	)		—			—
Debt issuance costs		(2,270	)		(675	)		(24,353	)
Other		(1,545	)		(8	)		(1,069	)
Net Cash Provided by (Used in) Financing Activities		(62,795	)		132,016			829,488
Net Increase (Decrease) in Cash and Cash Equivalents		(80,037	)		149,178			(42,605	)
Cash and Cash Equivalents, beginning of year		168,962			19,784			62,389
Cash and Cash Equivalents, end of year	$	88,925		$	168,962		$	19,784

 
 
See Accompanying Notes to Consolidated Financial Statements

56

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies

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

On December 5, 2008, we formed a new company, Energy XXI, Inc. which is now the parent company of our U.S. operations. The company was capitalized by Energy XXI (US Holdings) Limited’s contribution of all of the capital stock of Energy XXI USA, Inc. and certain Energy XXI Gulf Coast, Inc.’s bonds.

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

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

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 unevaluated 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 also allocate a portion of our acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

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 are difficult to predict. As discussed in Note 3 of Notes to Consolidated Financial Statements, we recorded a write-down to our oil and gas properties in the second and third quarters of fiscal 2009. At June 30, 2009, 2008 and 2007, a 10 percent decrease in oil and gas prices would not impact the results of our full cost ceiling limitation test.

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

Use of Estimates.  The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test

57

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

limitation. Accordingly, our accounting estimates require exercise of judgment. While we believe that the estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

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

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

Allowance for Doubtful Accounts.  We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2009 and 2008, no allowance for doubtful accounts was necessary.

General and Administrative Expense.  Under the full cost method of accounting, a portion of our general and administrative expense that is directly identified with our acquisition, exploration and development activities is capitalized as part of oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to directly support those employees that are directly involved in acquisition, exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities. Our capitalized general and administrative expense directly related to our acquisition, exploration and development activities for the years ended June 30, 2009, 2008 and 2007 was $17.3 million, $17.7 million and $7.7 million, respectively.

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, which includes, leasehold improvements, office and computer equipment and vehicles are stated at original cost and are depreciated using the straight-line method over the useful life of the assets, which ranges from three to five years.

Capitalized Interest.  Oil and natural gas investments in significant unproved properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs. Capitalized interest cannot exceed gross interest expense. As excluded oil and natural gas costs are transferred to the depreciable base, the associated capitalized interest is also transferred. For the years ended June 30, 2009, 2008 and 2007, we have not capitalized any interest expense.

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

58

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

In August 2008, Hurricane Gustav and in September 2008 Hurricane Ike damaged certain of our facilities in the Gulf of Mexico which increased our abandonment costs and changed the timing of the estimated abandonment.

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 straight-line method, which approximates the interest method.

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

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

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

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

We adopted the provisions of FIN 48 and applied the guidance of FIN 48-1 as of July 1, 2007. As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of FIN 48 or have any gross unrecognized tax benefit. At June 30, 2009, we did not have any FIN 48 liability or gross recognized tax benefit.

59

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Share-Based Compensation.  As of July 1, 2007, we adopted SFAS No. 123 (revised 2004) (“SFAS No. 123(R)”), Share-Based Payment. In accordance with SFAS No. 123(R), compensation cost is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award.

Note 2 — Recent Accounting Pronouncements

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

Modernization of Oil and Gas Reporting.  In December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which is effective January 1, 2010 for reporting 2009 oil and gas reserve information. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure also requires companies to include nontraditional resources such as oil sands, shale, coalbeds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently the SEC requires that reserve volumes are determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the prior twelve-month period rather than year-end prices. The twelve-month average price will also be used for purposes of calculating future net cash flows from proved oil and gas reserves for the SEC full cost ceiling limitations, and the results will not be subject to a single day pricing mechanism. Although the Financial Accounting Standards Board (“FASB”) currently requires the price on the last day of the reporting period to be used for accounting purposes, the FASB has added it to their agenda to conform with the SEC. The new requirements also will allow companies to disclose their probable and possible reserves to investors and will require companies to report the independence and qualifications of their reserve preparer or auditor. We will adopt the provisions of the release for our June 30, 2010 Annual Report on Form 10-K. We are currently evaluating the impact of the release.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.  In April 2009, the FASB issued FASB Staff Position (“FSP”) FAS 157-4 Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”) and FSP FAS 107-1 and APB 28-1 Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). These FSPs are effective for interim reporting periods ending after June 15, 2009, with early adoption permitted; however, early adoption requires that the FSPs are adopted concurrently.

FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157, Fair Value Measurements (“SFAS 157”), when the volume and level of activity for the asset or liability have significantly decreased, as well as guidance for identifying circumstances that indicate a transaction is not orderly. This FSP emphasizes that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date under current market conditions.

FSP FAS 107-1 and APB 28-1 amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 — Recent Accounting Pronouncements  – (continued)

The adoption of these FSP’s did not have an impact on our consolidated financial position, results of operations or cash flows.

Subsequent Events.  In May 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS 165”), which establishes principles and requirements for subsequent events. This statement defines the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, and the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements. SFAS 165 also sets forth the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 is effective for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 did not have an impact on our consolidated financial position, results of operations or cash flows. We evaluate events and transactions that occur after the balance date but before the financial statements are issued. We evaluated such events and transactions through September 4, 2009, when the financial statements were electronically filed with the SEC.

Amendments to FASB Interpretation (“FIN”) No. 46(R) (“FIN 46(R)”).  In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation (“FIN”) No. 46(R) (“FIN 46(R)”), (“SFAS 167”). The amendments include: (1) the elimination of the exemption for qualifying special purpose entities, (2) a new approach for determining who should consolidate a variable-interest entity, and (3) changes to when it is necessary to reassess who should consolidate a variable-interest entity. This statement is effective for fiscal years beginning after November 15, 2009, and for interim periods within that first annual reporting period. We are currently evaluating the impact of this standard.

Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.  In June 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. Emerging Issues Task Force (“EITF”) 03-6-1 (“FSP 03-6-1”), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share under the two-class method described in SFAS No. 128, Earnings Per Share. FSP 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years and will require all earnings per share data presented for prior-periods to be restated retrospectively. We currently do not anticipate that FSP 03-6-1 will have a material impact on our earnings per share data for fiscal year 2010 or on earnings per share data for any prior periods presented.

Accounting for Business Combinations.  In December 2007, the FASB issued SFAS No. 141R, Business Combinations (“SFAS 141R”), which replaces SFAS No. 141, Business Combinations. SFAS 141R establishes principles and requirements for determining how an enterprise recognizes and measures the fair value of certain assets and liabilities acquired in a business combination, including non-controlling interests, contingent consideration, and certain acquired contingencies. SFAS 141R also requires acquisition-related transaction expenses and restructuring costs be expensed as incurred rather than capitalized as a component of the business combination. SFAS 141R will be applicable prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS 141R would have an impact on accounting for any businesses acquired after the date of adoption, which is July 1, 2009 for the Company.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Impairment of Oil and Gas Properties

Ceiling Test.  Under the full cost method of accounting, we are required to perform each quarter, a “ceiling test” that determines a limit on the book value of our oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10 percent, net of related tax effects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. Future net cash flows are based on period-end commodity prices and exclude future cash outflows related to estimated abandonment costs. As of the reported balance sheet date, capitalized costs of an oil and gas producing company may not exceed the full cost limitation calculated under the above described rule based on current spot market prices for oil and natural gas. However, if prior to the balance sheet date, the company enters into certain hedging arrangements for a portion of its future natural gas and oil production, thereby enabling the company to receive future cash flows that are higher than the estimated future cash flows indicated by use of the spot market price as of the reported balance sheet date, these higher hedged prices are used if they qualify as cash flow hedges under the provisions of Statement 133 as amended.

Because of the significant decline in crude oil and natural gas prices, coupled with the impact of Hurricanes Gustav and Ike, we recognized a non-cash write-down of the net book value of our oil and gas properties of $117.9 million and $459.1 million in the third and second quarters of fiscal 2009, respectively. The write-downs were reduced by $179.9 million and $203.0 million pre-tax as a result of our hedging program in the third and second quarters of fiscal 2009, respectively.

Note 4 — Acquisitions

Partnership

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

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

The following table presents the allocation of our 49.5 percent interest of the assets acquired and liabilities assumed, based on their fair values on July 1, 2007 (in thousands):

Net working capital	$	5,678
Other assets		510
Oil and natural gas properties		29,947
Total Assets	$	36,135
Long-term debt	$	36,135

On November 30, 2007, our proportionate share of the Partnership assets and liabilities were distributed to us. On December 3, 2007, we paid off our proportionate share of the Partnership debt utilizing our First Lien revolver.

62

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Acquisitions  – (continued)

East Cameron Field

In July 2007, we acquired from ExxonMobil for $3.5 million plus assumption of asset retirement obligations, their approximately 30 percent interest in the East Cameron 334/335 Field in the Gulf of Mexico. We had previously acquired an interest in this field from Pogo Producing Company.

Pogo Properties

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

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

Subsequent to closing, it was determined that the preference rights related to the South Pass 49 pipeline would not be exercised, so we paid an additional $3 million to Pogo, which was accrued at June 30, 2007. We received a preliminary settlement in December 2007 and received the final settlement statement in July 2008 for the properties’ operations for the period from the effective date (April 1, 2007) to the closing date. The allocation between evaluated properties and unevaluated properties is preliminary.

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

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

Castex

On June 7, 2006, we entered into a definitive agreement with a number of sellers to acquire certain oil and natural gas properties in Louisiana (the “Castex Acquisition”). We closed the Castex Acquisition on July 28, 2006. Our cash cost of the acquisition was approximately $311.2 million.

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

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

63

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Acquisitions  – (continued)

Pogo and Castex Pro Forma Information (Unaudited)

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

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

The following table reflects the cash acquisition costs for the year ended June 30, 2008 (in thousands):

	Year Ended June 30, 2008
Partnership Acquisition and Closing Adjustment	$	32,544
East Cameron 334/335 Field Acquisition		3,521
East Cameron 334/335 Field Closing Adjustment		(136	)
POGO Acquisition Closing Adjustment		2,536
Marlin Closing Adjustment		1,523
Castex Acquisition Closing Adjustment		28
	$	40,016

Note 5 — Property and Equipment

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

	June 30,
	2009		2008
Oil and gas properties
Proved properties	$	2,227,462	$	1,816,313
Less: Accumulated depreciation, depletion, amortization and impairment		1,262,355		470,718
Proved properties – net		965,107		1,345,595
Unproved properties		137,489		215,681
Oil and gas properties – net		1,102,596		1,561,276
Other property and equipment		14,508		12,898
Less: Accumulated depreciation		5,359		2,878
Other property and equipment – net		9,149		10,020
Total property and equipment	$	1,111,745	$	1,571,296

64

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt

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

	June 30,
	2009		2008
First lien revolver	$	234,531	$	192,000
High yield facility		624,000		750,000
Put premium financing		3,851		9,697
Capital lease obligation		445		525
Total debt		862,827		952,222
Less current maturities		4,107		7,250
Total long-term debt	$	858,720	$	944,972

Maturities of long-term debt as of June 30, 2009 are as follows (in thousands):

Year Ending June 30,
2010	$	4,107
2011		234,720
2013		624,000
Total	$	862,827

First Lien Revolver

Our first lien revolver was amended and restated on June 8, 2007. This facility was entered into by our subsidiary, EGC. This facility has a face value of $700 million and matures on June 8, 2011. The credit facility bore interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 1.50 percent to 2.25 percent or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.50 percent to 1.25 percent. However, if an additional equity contribution in an amount of at least $50 million is made by us to EGC, all of the margins above will be subject to a 0.25 percent reduction. This equity investment was made in June 2008. The credit facility is secured by mortgages on at least 85 percent of the value of our proved reserves. Our initial borrowing base under the facility was $425 million.

On November 19, 2007, the credit facility was further amended. The amendment, among other things, increased the borrowing base to $450 million and modified the commodity hedge limitations and minimum liquidity during certain periods. We incurred $0.7 million to amend the first lien revolver including $0.5 million associated with syndicating the credit facility.

On December 9, 2008, the credit facility was again amended. The amendment, among other things, reduced the borrowing base to $400 million. The amendment provides protection to other lenders should any bank in the syndicate fail to fund their share of the revolver and other provisions which effectively reduce the available borrowing base to $380 million and carves out certain derivative contracts from the hedge limits contained in the revolver.

On April 6, 2009 the credit facility was again amended. The amendment, among other things, reduced the borrowing base to $240 million, amended the financial covenants related to the total leverage ratio to 4.5 to 1.0 commencing with the quarter ended June 30, 2009 and added a secured debt ratio not to exceed 2.5 to 1.0 beginning with the quarter ended June 30, 2009. The amendment also modified the interest rates payable under the facility and pledged the EGC bonds held by us as security.

Our first lien revolving credit facility requires us to maintain certain financial covenants. Specifically, EGC may not permit its total leverage ratio to be more than 4.5 to 1.0 with certain reductions in this ratio over time (which was amended on April 6, 2009), our interest rate coverage ratio to be less than 3.0 to 1.0, a

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

secured debt ratio to be more than 2.5 to 1.0, or our current ratio (in each case as defined in our first lien revolving credit facility) to be less than 1.0 to 1.0, in each case, as of the end of each fiscal quarter. In addition, we are subject to various covenants including those limiting dividends and other payments, making certain investments, margin, consolidating, modifying certain agreements, transactions with affiliates, the incurrence of debt, changes in control, asset sales, liens on properties, sale leaseback transactions, entering into certain leases, the allowance of gas imbalances, take or pay or other prepayments, entering into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr., Steven A. Weyel and David West Griffin in their current executive positions, subject to certain exceptions in the event of death or disability to one of these individuals.

The first lien revolving credit facility also contains customary events of default, including, but not limited to non-payment of principal when due, non-payment of interest or fees and other amounts after a grace period, failure of any representation or warranty to be true in all material respects when made or deemed made, defaults under other debt instruments (including the indenture governing the notes), commencement of a bankruptcy or similar proceeding by or on behalf of us or a guarantor, judgments against us or a guarantor, the institution by us to terminate a pension plan or other ERISA events, any change in control, loss of liens, failure to meet financial ratios, and violations of other covenants subject, in certain cases, to a grace period. As of June 30, 2009, we are in compliance with all covenants.

High Yield Facility

On June 8, 2007 our subsidiary, EGC, completed a $750 million private offering of 10 percent Senior Notes due 2013 (“Old Notes”). As part of the private offering EGC agreed to use its best efforts to complete an exchange offer, which it completed on October 16, 2007. In the exchange offer, the Old Notes were exchanged for $750 million of 10 percent Senior Notes due 2013 that have been registered under the Securities Act of 1933 (“New Notes”), with terms substantially the same as the Old Notes. All of the issued and outstanding Old Notes were exchanged for New Notes. We did not receive any cash proceeds from the exchange offer.

The notes are guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We have the right to redeem the new notes under various circumstances and are required to make an offer to repurchase the new notes upon a change of control and from the net proceeds of asset sales under specified circumstances.

As of June 30, 2009, we have purchased a total of $126.0 million total face amount of the New Notes at an average cost of 72.13, or $90.9 million, plus accrued interest of an incremental $3.3 million for a total cost of $94.2 million. The New Notes were paid from utilizing a portion of the total warrant proceeds from the warrant tender offer. The purchased New Notes remain outstanding and accrue interest at 10 percent. When reflected in the consolidated financials, the face amount of New Notes repurchased reduce the total amount of New Notes outstanding from $750 million to $624 million, and the interest expense is eliminated against the interest income at the consolidated level. The $35.1 million pre-tax gain on the New Notes repurchased is deferred and is amortized over the remaining life of the New Notes as the New Notes have not been retired.

We believe that the fair value of our high yield facility as of June 30, 2009 was $371 million.

Put Premium Financing

We finance puts that we purchase with our hedge providers. Substantially all of our hedges are done with members of our bank groups. Put financing is accounted for as debt and this indebtedness is pari pasu with borrowings under the first lien revolving credit facility. The hedge financing is structured to mature when the put settles so that we realize the value net of hedge financing. As of June 30, 2009 and June 30, 2008, our outstanding hedge financing totaled $3.9 million and $9.7 million, respectively.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

Interest Expense

Interest expense for the year ended June 30, 2009 was $84.2 million, which includes $5.2 million of amortization of debt issuance costs, $77.9 million associated with the high yield facility and the first lien revolver and $1.1 million associated with the put premium financing and other.

Interest expense for the year ended June 30, 2008 was $103.3 million, which includes $4.3 million of amortization of debt issuance costs, $97.6 million associated with the high yield facility, the first lien revolver and the Partnership debt and $1.4 million associated with the put premium financing and other.

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

Note 7 — Note Payable

In July 2008, we entered into a $17.2 million note payable with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was payable in 11 monthly installments of $1,589,988, including interest at an annual rate of 3.249 percent, beginning August 1, 2008. The note has been paid off as of June 30, 2009.

Note 8 — Asset Retirement Obligations

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

	Year Ended June 30,
	2009			2008
Balance at beginning of year	$	97,814		$	75,829
Liabilities acquired		—			12,863
Liabilities incurred		4,152			12,230
Liabilities settled		(40,123	)		(21,500	)
Revisions in estimated cash flows(1)		67,721			10,216
Accretion expense		14,635			8,176
Total balance at end of year		144,199			97,814
Less current portion(1)		66,244			16,717
Long-term balance at end of year	$	77,955		$	81,097

(1) The revisions in estimated cash flows and the related current portion of asset retirement obligations relate primarily to the impact of Hurricanes Gustav and Ike, which impacted both the estimated cost of the abandonment of certain facilities as well as the timing of the abandonment.

Note 9 — Derivative Financial Instruments

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

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

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

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

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the year ended June 30, 2009 resulted in an increase in crude oil and natural gas sales in the amount of $42.7 million. For the year ended June 30, 2009, we recognized a gain of approximately $1.5 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $9.9 million and an unrealized loss of approximately $1.3 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the year ended June 30, 2008 resulted in a decrease in crude oil and natural gas sales in the amount of $78.9 million. For the year ended June 30, 2008, we recognized a gain of approximately $0.5 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized loss of approximately $3.9 million and an unrealized loss of approximately $2.7 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

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

In March 2009, we monetized certain hedge positions and received cash proceeds of $66.5 million. These amounts are carried in stockholders’ equity as part of other comprehensive income and will be recognized in income over the contract life of the underlying hedge contracts. Crude oil and natural gas sales were increased by $17.9 million for the year ended June 30, 2009 and will be increased by $38.2 million and $10.4 million for the years ended June 30, 2010 and 2011, respectively, as a result of the amortization of these monetized hedges.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

As of June 30, 2009, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) in thousands):

	Crude Oil										Natural Gas
					Total										Total						Total
Period	Volume (MBbls)		Contract Price(1)		Asset (Liability)			Fair Value (Loss)			Volume (MMMBtus)		Contract Price(1)		Asset (Liability)			Fair Value (Loss)			Asset (Liability)			Fair Value (Loss)(2)
Put Spreads
7/09 – 6/10		591		82.90/107.16	$	12,343		$	6,377			5,140	$	6.18/8.30	$	9,830		$	4,064		$	22,173		$	10,441
Swaps
7/09 – 6/10		1,481		72.92		(17,617	)		(11,357	)		6,320		4.93		5,753			4,817			(11,864	)		(6,540	)
7/10 – 6/11		653		76.54		(4,993	)		(3,511	)		3,392		6.61		(3,510	)		(1,090	)		(8,503	)		(4,601	)
7/11 – 6/12		97		78.96		(554	)		(360	)		2,208		6.59		139			87			(415	)		(273	)
						(23,164	)		(15,228	)						2,382			3,814			(20,782	)		(11,414	)
Collars
7/00 – 6/10		364		78.26/107.86		3,673			1,746													3,673			1,746
7/10 – 6/11		196		77.29/106.12		1,641			723													1,641			723
						5,314			2,469													5,314			2,469
Three-Way Collars
7/09 – 6/10		287		52.70/67.43/81.57		(292	)		(190	)		5,790		6.00/8.21/10.15		8,150			4,900			7,858			4,710
7/10 – 6/11		97		51.27/66.27/82.03		(436	)		(283	)		5,990		5.85/8.00/10.27		6,158			3,999			5,722			3,716
7/11 – 6/12												1,840		5.50/7.50/10.55		855			552			855			552
						(728	)		(473	)						15,163			9,451			14,435			8,978
Total					$	(6,235	)	$	(6,855	)					$	27,375		$	17,329		$	21,139		$	10,474

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

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

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

The following table quantifies the fair values, on a gross basis, of all our derivative contracts and identifies its balance sheet location as of June 30, 2009 (In thousands):

	Asset Derivatives				Liability Derivatives
	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Derivatives designated as hedging instruments under Statement 133
Commodity Contracts		Derivative financial instruments				Derivative financial instruments
		Current	$	45,886		Current	$	27,901
		Non-current		9,419		Non-current		7,769
				55,305				35,670
Interest Rate Contracts						Derivative financial instruments
						Current		3,474
Total derivatives designated as hedging instruments under Statement 133				55,305				39,144
Derivatives not designated as hedging instruments under Statement 133
Commodity Contracts		Derivative financial instruments				Derivative financial instruments
		Current		3,693		Current		2,532
		Non-current		1,082		Non-current		3,712
				4,775				6,244
Total derivatives			$	60,080			$	45,388

The following table quantifies the fair values, on a gross basis, the effect of derivatives on our financial performance and cash flows for the year ended June 30, 2009 (in thousands):

Derivatives in Statement 133 Cash Flow Hedging Relationships	Amount of (Gain) Loss Recognized in Income on Derivative (Effective Portion)						Location of (Gain) Loss Reclassified from Accumulated OCI into Income (Effective Portion)		Amount of (Gain) Loss Reclassified from Accumulated OCI into Income (Effective Portion)						Location of (Gain) Loss Recognized in Income on Derivative (Ineffective Portion)		Amount of (Gain) Loss Reclassified from Accumulated OCI into Income (Ineffective Portion)
	Qtr			YTD					Qtr			YTD					Qtr		YTD
Commodity Contracts	$	41,880		$	(323,693	)		Revenue	$	(27,011	)	$	(42,662	)		Gain/(Loss) on derivative financial instruments	$	2,150	$	(1,538	)
Interest Rate Contracts		(333	)		186			Interest expense		813			2,292			Gain/(Loss) on derivative financial instruments		—		—
Total	$	41,547		$	(323,507	)			$	(26,198	)	$	(40,370	)			$	2,150	$	(1,538	)

Derivatives Not Designated as Hedging Instruments Under Statement 133	Location of (Gain) Loss Recognized in Income on Derivative		Amount of (Gain) Loss Recognized in Income on Derivative
			Qtr			YTD
Commodity Contracts		(Gain) loss on derivative financial instruments	$	(3,316	)	$	(8,609	)

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

We have reviewed the financial strength of our hedge counterparties and believe the credit risk to be minimal. At June 30, 2009, we had no deposits for collateral with our counterparties.

On June 26, 2006, we entered into an interest rate costless collar to mitigate the risk of loss due to changes in interest rates. The dollar amount hedged was $75 million with the interest rate collar being 5.45 percent to 5.75 percent. At June 30, 2009, we had deferred $2.3 million, net of tax benefit, in losses in OCI related to this instrument.

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

	Year Ended
	June 30, 2009			June 30, 2008
Balance at beginning of year	$	(285,010	)	$	2,764
Hedging activities:
Commodity
Change in fair value (loss)		162,536			(279,380	)
Reclassified to income (loss)		161,157			(6,663	)
Interest rate
Change in fair value (loss)		(2,444	)		(1,841	)
Reclassified to income		2,258			110
Balance at end of year	$	38,497		$	(285,010	)

The amounts expected to be reclassified to income in the next 12 months are $32.5 million income on our commodity hedges and a $3.5 million loss on our interest rate hedge.

Note 10 — Stockholders’ Equity

Common Stock

Our common stock trades on NASDAQ and on the London Stock Exchange Alternative Investment Market (“AIM”) under the symbol “EXXI.” Our restricted common stock trades on the AIM under the symbol “EXXS.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders.

As of June 30, 2009 and 2008, we have 679,674 shares and 362,556 shares, respectively, of our common stock, which we repurchased in the open market at a cost of approximately $2.8 million and $2.2 million, respectively that we plan to reissue, in lieu of cash, to our employees within one year in connection with our 2006 Long-Term Incentive Plan. The cost of such shares is included in other current assets on the accompanying consolidated balance sheet.

Preferred Stock

Our bye-laws authorize the issuance of 2,500,000 shares of preferred stock. Our Board of Directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. We have not issued any preferred stock as of June 30, 2009 and 2008.

Warrants

We issued 100,000,000 warrants to stockholders in October 2005 as part of its admission to trading on the AIM. Each warrant entitles the holder to purchase one common share at a price of $5.00 per share. The warrants will be redeemable, at any time after they become exercisable, upon written consent of the placing agents, at a price of $0.01 per warrant upon 30 days notice after the warrants become exercisable, if, and only

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 — Stockholders’ Equity  – (continued)

if, the last independent bid price of the common shares equals or exceeds $8.50 per share for any 20 trading days within a 30 trading day period ending three business days before we send the notice of redemption and the weekly trading volume of our common shares has exceeded 800,000 for each of the two calendar weeks before we send the notice of redemption. Investors will be afforded the opportunity to exercise the warrants on margin and simultaneously sell the shares for a “cashless exercise” if we call the warrants. The warrants will expire October 20, 2009.

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

As of June 30, 2009 and 2008, we had 12,977,417 outstanding warrants exercisable for $5 per share. In May 2008, we announced a tender offer for the outstanding warrants under the following three options: the warrant holder would receive one unrestricted common share for every five Warrants tendered (“Cashless Option”); the warrant holder would receive two unrestricted common shares for every three Warrants and $6.35 cash payment tendered (“Cash Option”); and/or the warrant holder would receive one unrestricted common share for every Warrant and $4.00 cash payment tendered (“Reduced Cash Option”). A total of 64,104,055 warrants were exchanged for 60,529,369 shares of common stock. In addition, 258,400 warrants were exercised at $5.00 per warrant. Total cash inflow related to these two items was approximately $237.8 million. We also repurchased 50,000 warrants at a cost of $20,000 in April 2008.

Unit Purchase Option

As part of the placement on the AIM in October 2005, we issued to an underwriter and its designees (including its officers) an option (exercisable in whole or part) to subscribe up to 5,000,000 Units at a price of $6.60 per Unit. Each unit would consist of one common share and two warrants. The warrants would each be convertible into a share of our common stock at $5.00 per share with an expiration date of October 20, 2009. Fair value of the options, determined by using the Black-Scholes pricing model, was approximately $8.2 million, and recorded as a cost of the Placement in stockholders’ equity and additional paid-in capital. The options expire on October 20, 2010. There were no unit purchase options exercised at June 30, 2009, 2008 and 2007.

Note 11 — Supplemental Cash Flow Information

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

	Year Ended June 30,
	2009		2008			2007
Cash paid for interest	$	76,323	$	97,937		$	48,630
Cash paid (received) for income taxes		716		(2,000	)		2,400

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

	Year Ended June 30,
	2009		2008		2007
Additions to property and equipment by recognizing accounts payables	$	20,929	$	48,595	$	50,866
Put premiums acquired through financing		2,598		7,097		—
Additions to property and equipment by recognizing asset retirement obligations		4,152		12,230		4,618

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans

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

At our discretion, at the time the Phantom Stock units vest, we have the ability to offer the employee an option to either accept common shares in lieu of cash or to accept cash. Upon a change in control of the Company, all outstanding Phantom Stock units become immediately vested and payable.

As of June 30, 2009, we have 3,384,543 unvested Phantom Stock units. In addition, we have outstanding 709,819 unvested Restricted Shares as of June 30, 2009. For the year ended June 30, 2009, we recognized compensation expense of $2.4 million. A liability has been recognized as of June 30, 2009 in the amount of $0.7 million, in accrued liabilities in the accompanying consolidated balance sheet. The amount of the liability will be remeasured at fair value as of each reporting date.

Restricted Shares activity is as follows:

	Number of Shares			Grant-Date Fair Value per Share
Non-vested at June 30, 2007		78,334		$	4.89
Granted on July 1, 2007		292,500			6.65
Vested during fiscal 2008		(39,168	)
Non-vested at June 30, 2008		331,666			6.44
Granted on July 23, 2008		153,250			4.95
Granted on September 16, 2008		459,069			4.95
Vested during fiscal 2009		(234,166	)
Non-vested at June 30, 2009		709,819		$	5.18

We determine the fair value of the Restricted Shares based on the market price of our Common Stock on the date of grant. Compensation cost for the Restricted Shares is recognized on a straight line basis over the vesting or service period. As of June 30, 2009 there was approximately $2.7 million of unrecognized compensation cost related to non-vested Restricted Shares. We expect approximately $1.6 million to be recognized over fiscal 2010, $1.0 million to be recognized during the fiscal year ended 2011 and $0.1 million to be recognized during the fiscal year ended 2012.

Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of Common Stock that have either been purchased by us on the open market or that have been newly issued by us.

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan which allows employees to purchase common stock at a 15 percent discount from the lower of the common stock closing price on the first or last day of the period. The initial period was from December 1, 2008 to June 30, 2009. At June 30, 2009, we had charged $234,000 to compensation expense related to this plan. The plan has a limit of 5,000,000 common shares.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans  – (continued)

Defined Contribution Plans.  Our employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions that can vary from year to year. We also sponsor a qualified 401(k) Plan that provides for matching. The cost to us under these plans for the years ended June 30, 2009, 2008 and 2007 was $1.6 million, $1.7 million and $0.8 million and $1.2 million, $1.4 million and $0.4 million, respectively.

Note 13 — Related Party Transactions

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

Note 14 — Earnings per Share

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

	Year Ended June 30,
	2009			2008		2007
Net income (loss)	$	(571,629	)	$	26,869	$	24,130
Weighted average shares outstanding for basic EPS		144,593			85,809		83,959
Add dilutive securities: warrants and unit purchase options		—			4,462		—
Weighted average shares outstanding for diluted EPS		144,593			90,271		83,959
Earnings (loss) per share
Basic	$	(3.95	)	$	0.31	$	0.29
Diluted		(3.95	)		0.30		0.29

For the year ended June 30, 2009, 1,221,217 common stock equivalents were excluded from the diluted average shares due to an anti-dilutive effect.

Note 15 — Hurricanes Katrina, Rita, Gustav and Ike

We have interest in properties that were damaged by hurricanes Katrina and Rita. Our insurance coverage is an indemnity program that provides for reimbursement after funds are expended. In January 2007, we reached a global settlement for $38.8 million with our insurance carrier. The entire amount has been received.

We also incurred property damage by hurricanes Gustav and Ike. As of June 30, 2009, we have incurred approximately $35.8 million of costs and have been reimbursed $27.9 million by our insurance carrier.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Commitments and Contingencies

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

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on December 31, 2017. Future minimum lease commitments as of June 30, 2009 under the operating lease are as follows (in thousands):

Year Ending June 30,
2010	$	1,349
2011		1,349
2012		1,349
2013		1,349
2014		1,349
Thereafter		4,712
Total	$	11,457

Rent expense, including rent incurred on short-term leases, for the years ended June 30, 2009, 2008 and 2007 was approximately $2,209,000, $1,391,000 and $735,000, respectively.

Letters of Credit and Performance Bonds.  We had $1.1 million in letters of credit and $11.8 million of performance bonds outstanding as of June 30, 2009.

Drilling Rig Commitments.  As of June 30, 2009, we have a drilling rig commitment for approximately thirty-six days to be used in the future at a total cost of $2.0 million.

Note 17 — Income Taxes

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

During the year ended June 30, 2009, we incurred a significant impairment loss of our oil and gas properties due to the steep decline in global energy prices over that same time period. As a result, we are in a position of cumulative reporting losses for the current and preceding reporting periods. The volatility of energy prices and uncertainty of when energy prices may rebound is problematic and not readily determinable by our management. At this date, this general fact pattern does not allow us to project sufficient sources of future taxable income to offset our tax loss carryforwards and net deferred tax assets in the U.S. Under these current circumstances, it is management’s opinion that the realization of these tax attributes beyond the reversal of existing taxable temporary differences does not reach the “more likely than not” criteria under FAS 109. As a result, we have established a valuation allowance of $175.0 million, at June 30, 2009, against our U.S. net deferred tax assets and the change in the valuation allowance during the year is this same amount.

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

	Year Ended June 30,
	2009			2008		2007
	(In Thousands)
U.S. income (loss)	$	(632,145	)	$	17,162	$	14,215
Non-U.S. income		38,177			24,581		22,580
Income (loss) before income taxes	$	(593,968	)	$	41,743	$	36,795

75

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Income Taxes  – (continued)

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

	Year Ended June 30,
	2009			2008		2007
	(In Thousands)
Current
United States	$	—		$	—	$	(837	)
Non U.S.		716			—		—
State		—			4		(28	)
Total current		716			4		(865	)
Deferred
United States		(23,055	)		14,769		11,993
State		—			101		1,537
Total deferred		(23,055	)		14,870		13,530
Total income tax provision (benefit)	$	(22,339	)	$	14,874	$	12,665

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

	Year Ended June 30,
	2009			2008			2007
	(In Thousands)
Income (loss) before income taxes	$	(593,968	)	$	41,743		$	36,795
Statutory rate		35	%		35	%		35	%
Income tax expense (benefit)computed at statutory rate		(207,889	)		14,610			12,878
Reconciling items
Federal withholding obligation		11,053			8,473			7,477
Non taxable foreign income		(13,362	)		(8,603	)		(7,903	)
Change in valuation allowance		174,966			—			—
Debt cancelation – bond repurchase		12,289			—			—
State income taxes, net of federal tax benefit		—			103			980
Other-net		604			291			(767	)
Tax provision (benefit)	$	(22,339	)	$	14,874		$	12,665

76

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Income Taxes  – (continued)

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

	June 30,
	2009			2008		2007
	(In Thousands)
Deferred tax assets
Asset retirement obligation	$	30,478		$	34,234	$	26,540
Tax loss carryforwards on U.S. operations		63,518			60,705		89,278
Capital loss carryforward		12,242
Derivative instruments		—			154,345		—
Accrued interest expense		31,467			19,407		9,604
Employee benefit plans		1,225			2,550		641
Oil and natural gas properties		69,207			—		—
Other		—			—		451
Total deferred tax assets		208,137			271,241		126,514
Deferred tax liabilities
Derivative instruments and other		2,425			—		1,495
Oil and natural gas properties		—			106,802		117,656
Federal withholding obligation		26,972			16,635		8,238
Other property and equipment		13,433			10,941		10,697
Deferred state tax obligation		1,100			1,100		4,260
Other		16,130			11,510		—
Total deferred tax liabilities		60,060			146,988		142,346
Valuation allowance		174,966			—		—
Net deferred tax asset (liability)	$	(26,889	)	$	124,253	$	(15,832	)
Reflected in the accompanying balance sheet as
Current deferred tax asset	$	—		$	88,198	$	—
Current deferred tax liability		—			—		(1,044	)
Non-current deferred tax asset		—			36,055		—
Non-current deferred tax liability		(26,889	)		—		(14,788	)
Net deferred tax asset (liability)	$	(26,889	)	$	124,253	$	(15,832	)

At June 30, 2009, we have a federal tax loss carryforward (“NOLs”) of approximately $182 million, a state income tax loss carryforward of approximately $223 million and a federal capital loss carryforward of $35 million. The income tax NOLs will expire in various amounts beginning in 2021 and ending in 2029 and the federal capital loss has a 5 year carryforward period that will expire in 2014.

Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an “ownership change.” In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation by more than 50 percentage points over a three year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382 determined by multiplying the value of the Company’s stock at the time of the ownership change by the applicable long-term tax exempt rate (which is 4.57% for the month of June 2008). Any unused annual limitation may be carried over to later

77

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Income Taxes  – (continued)

years. The amount of the limitation may, under certain circumstances, be increased by the built-in gains held by the Company at the time of the ownership change that are recognized in the five year period after the change. The Company experienced an ownership change on June 20, 2008 due in significant part to the exchange of warrants for common stock. Based upon the Company’s preliminary determination of its annual limitation related to this ownership change, management believes that Section 382 should not otherwise limit the Company’s ability to utilize its federal or state NOLs during their applicable carryforward periods.

We adopted the provisions of FIN 48 and applied the guidance of FIN 48-1 as of July 1, 2007. As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of FIN 48 or have any gross unrecognized tax benefit. At June 30, 2009, we did not have any FIN 48 liability or gross unrecognized tax benefit.

We filed our initial tax return for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 and 2008. These tax years are open for examination by the U.S. and state taxing authorities.

Note 18 — Concentrations of Credit Risk

Major Customers.  We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

Shell Trading Company (“Shell”) accounted for approximately 65 percent, 62 percent and 35 percent of our total oil and natural gas revenues during the years ended June 30, 2009, 2008 and 2007, respectively. 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 or substantially all of our production in the event that Shell curtailed its purchases.

Accounts Receivable.  Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.

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

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

78

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 19 — Fair Value of Financial Instruments

On July 1, 2008, we adopted the provisions of SFAS No. 157, Fair Value Measurements. SFAS No. 157 expands the disclosure requirements for financial instruments and other derivatives recorded at fair value, and also requires that a company’s own credit risk, or the credit risk of the counterparty, as applicable, be considered in determining the fair value of those instruments. The adoption of SFAS No. 157 resulted in a $10 million pre-tax increase in other comprehensive income and a $10 million reduction of our liabilities, at July 1, 2008 to reflect the consideration of our credit risk on our liabilities that are recorded at fair value.

We use various methods to determine the fair values of our financial instruments and other derivatives which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For our natural gas and oil derivatives, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For our interest rate derivatives, the fair value may be calculated based on these inputs as well as third-party estimates of these instruments. We separate our financial instruments and other derivatives into two levels (Levels 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between levels. Each of these levels and our corresponding instruments classified by level are further described below:

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

• Level 3 instruments’ fair values are based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our valuation models are industry-standard and consider various inputs including third party broker-quoted forward amounts and time value of money.

Listed below are our financial instruments classified in each level and a description of the significant inputs utilized to determine their fair value at June 30, 2009 (in thousands):

	Level 2		Level 3		Total
Assets:
Natural Gas and Oil Derivatives	$	35,242			$	35,242
Liabilities:
Natural Gas and Oil Derivatives	$	17,076			$	17,076
Interest Rate Collar			$	3,474		3,474
Total Liabilities	$	17,076	$	3,474	$	20,550

The following table sets forth a reconciliation of changes in the fair value of derivatives classified as Level 3 (in thousands):

	Interest Rate Collar
Balance at July 1, 2008	$	3,187
Total loss included in other comprehensive income		2,579
Settlements		(2,292	)
Balance at June 30, 2009	$	3,474

79

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 19 — Fair Value of Financial Instruments  – (continued)

We include fair value information in the notes to the consolidated financial statements when the fair value of our financial instruments is different from the book value. We believe that the carrying value of our cash and cash equivalents, receivables, accounts payable, accrued liabilities and short-term and long-term debt, other than our high yield facility, materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the fair value of our high yield facility as of June 30, 2009 was $371 million.

Note 20 — Prepayments and Accrued Liabilities

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

	June 30,
	2009		2008
Prepaid expenses and other current assets
Advances to joint interest partners	$	7,858	$	10,096
Insurance		168		173
Inventory		5,526		625
Other		2,766		3,768
Total prepaid expenses and other current assets	$	16,318	$	14,662
Accrued liabilities
Advances from joint interest partners	$	338	$	7,487
Employee benefits and payroll		8,096		12,755
Interest		4,855		5,269
Accrued hedge payable		8,179		20,153
Undistributed oil and gas proceeds		11,744		31,017
Other		2,968		5,471
Total accrued liabilities	$	36,180	$	82,152

Note 21 — Dividends

On September 9, 2008, the Board of Directors (“Board”) declared a Common Stock quarterly cash dividend of $0.005 per share, payable October 20, 2008 to shareholders of record on September 19, 2008. On February 6, 2009, the Board declared a cash dividend of $0.005 per common share, payable on March 13, 2009 to shareholders of record on February 20, 2009. With the borrowing base redetermination completed in April 2009, we agreed to cease declaring dividends until the next borrowing base redetermination is completed in the fall of 2009.

Note 22 — Subsequent Event

Insurance Note

On July 22, 2009, we entered into a note to finance a portion of our insurance premiums. The note is for a total face amount of $19.5 million and bears interest at an annual rate of 3.2 percent. The note amortizes over the remaining term of the insurance, which matures June 30, 2010.

80

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 23 — Selected Quarterly Financial Data – Unaudited

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

	Year Ended June 30, 2009
	Fourth Quarter			Third Quarter			Second Quarter			First Quarter
Revenues	$	101,098		$	106,136		$	106,852		$	119,744
Operating income (loss)		26,761			(102,114	)		(455,333	)		13,469
Net income (loss)	$	(17,157	)	$	(120,618	)	$	(429,203	)	$	(4,651	)
Basic earnings (loss) per common share(1)	$	(0.12	)	$	(0.84	)	$	(2.98	)	$	(0.03	)
Diluted earnings (loss) per common share(1)		(0.12	)		(0.84	)		(2.98	)		(0.03	)

	Year Ended June 30, 2008
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter
Revenues	$	178,762	$	167,137	$	153,725	$	143,608
Operating income		35,765		42,249		36,457		29,129
Net income	$	8,220	$	10,287	$	6,475	$	1,887
Basic earnings per common share(1)	$	0.09	$	0.12	$	0.08	$	0.02
Diluted earnings per common share(1)		0.08		0.12		0.07		0.02

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

Note 24 — Supplementary Financial Information — Unaudited

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

	Year Ended June 30,
	2009		2008		2007
	(In Thousands)
Oil and Gas Activities
Exploration costs	$	121,554	$	114,639	$	67,140
Development costs		168,134		205,681		362,219
Total		289,688		320,320		429,359
Administrative and Other		1,610		9,758		2,468
Total capital expenditures		291,298		330,078		431,827
Property acquisitions
Proved		—		38,124		632,707
Unproved		—		1,892		84,911
Total acquisitions		—		40,016		717,618
Asset retirement obligations and other – net		46,502		13,774		49,429
Total costs incurred	$	337,800	$	383,868	$	1,198,874

81

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24 — Supplementary Financial Information — Unaudited  – (continued)

We excluded the following costs related to unproved property costs and major development projects:

	Year Ended June 30,
	2009		2008		2007
	(In Thousands)
Unevaluated properties	$	137,489	$	215,681	$	243,981
Wells in progress		27,944		57,692		7,185
	$	165,433	$	273,373	$	251,166

Oil and natural gas property costs excluded represent investments in unevaluated 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 also allocate a portion of our acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir. The wells in progress will be transferred into the amortization base during fiscal 2010 when the results of the drilling activities are known.

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers (86 percent of our proved reserves on a valuation basis) and, the remainder, by our 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.

82

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24 — Supplementary Financial Information — Unaudited  – (continued)

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:

	Crude Oil (MBbls)			Natural Gas (MMcf)			Total (MBOE)
Proved reserves at June 30, 2006		13,820			64,651			24,595
Production		(2,852	)		(18,369	)		(5,914	)
Extensions and discoveries		4,726			37,235			10,932
Revisions of previous estimates		(523	)		(16,233	)		(3,229	)
Sales of reserves		(224	)		(991	)		(389	)
Purchases of minerals in place		15,393			85,539			29,650
Proved reserves at June 30, 2007		30,340			151,832			55,645
Production		(4,959	)		(27,716	)		(9,578	)
Extensions and discoveries		2,520			7,410			3,755
Revisions of previous estimates		1,909			(11,033	)		70
Sales of reserves		(21	)		(141	)		(45	)
Purchases of minerals in place		176			8,846			1,651
Proved reserves at June 30, 2008		29,965			129,198			51,498
Production		(4,146	)		(17,472	)		(7,058	)
Extensions and discoveries		971			32,383			6,368
Revisions of previous estimates		4,147			(10,447	)		2,406
Sales of reserves		(64	)		(247	)		(105	)
Proved reserves at June 30, 2009		30,873			133,415			53,109
Proved developed reserves
June 30, 2006		8,922			42,246			15,963
June 30, 2007		20,978			96,751			37,103
June 30, 2008		19,793			77,991			32,792
June 30, 2009		20,183			82,432			33,922

	June 30,
	2009				2008				2007
	Oil (Bbl)		Gas (MMbtu)		Oil (Bbl)		Gas (MMbtu)		Oil (Bbl)		Gas (MMbtu)
Commodity prices used in determining future cash flows	$	69.89	$	3.89	$	142.46	$	13.89	$	73.25	$	6.80

Standardized Measure of Discounted Future Net Cash Flows

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

83

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24 — Supplementary Financial Information — Unaudited  – (continued)

The standardized measure of discounted future net cash flows related to proved oil and gas reserves as of June 30, 2009, 2008 and 2007 are as follows (in thousands):

	June 30,
	2009		2008		2007
Future cash inflows	$	2,608,640	$	5,969,185	$	3,197,234
Less related future
Production costs		688,706		986,630		531,253
Development costs		522,193		660,124		582,664
Income taxes		71,876		1,036,581		253,350
Future net cash flows		1,325,865		3,285,850		1,829,967
Ten percent annual discount for estimated timing of cash flows		320,589		776,151		436,813
Standardized measure of discounted future net cash flows	$	1,005,276	$	2,509,699	$	1,393,154

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

	Year Ended June 30,
	2009			2008			2007
Beginning of year	$	2,509,699		$	1,393,154		$	474,498
Revisions of previous estimates
Changes in prices and costs		(2,200,286	)		1,628,049			119,317
Changes in quantities		183,783			20,088			(58,122	)
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		99,024			207,597			298,677
Purchases of reserves in place		—			109,877			859,709
Sales of reserves in place		(5,603	)		(1,641	)		(5,085	)
Accretion of discount		330,143			158,599			57,868
Sales, net of production costs		(306,230	)		(491,687	)		(268,704	)
Net change in income taxes		737,233			(598,896	)		(88,656	)
Changes in rate of production and other		(342,487	)		84,559			3,652
Net change		(1,504,423	)		1,116,545			918,656
End of year	$	1,005,276		$	2,509,699		$	1,393,154

84

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.

Management’s Annual Report on Internal Control Over Financial Reporting

Management’s Report on Internal Control over Financial Reporting is included in Item 8 of this report on page 50 and is incorporated herein by reference.

Changes in Internal Control Over Financial Reporting

There was no change in our system of internal control over financial reporting during our quarterly period ended June 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

85

PART III

Item 10. Directors, Executive Officers and Corporate Governance

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

We have adopted a Code of Business Conduct and Ethics, which covers a wide range of business practices and procedures. The Code of Business Conduct and Ethics also represents the code of ethics applicable to our principal executive officer, principal financial officer, and principal accounting officer or controller and persons performing similar functions (“senior financial officers”). A copy of the Code of Business Conduct and Ethics has been filed under Item 15 as Exhibit 14.1 to this report. We intend to disclose any amendments to or waivers of the Code of Business Conduct and Ethics on behalf of our senior financial officers on our website www.energyxxi.com under “Investor Relations” and “corporate Governance” promptly following the date of the amendment or waiver.

Item 11. Executive Compensation

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

Item 12. Security Ownership of Certain Beneficial Owners and Management Related Stockholder Matters

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

Item 13. Certain Relationships and Related Transactions, and Director Independence

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

Item 14. Principal Accounting Fees and Services

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

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) The following documents are filed as a part of this report or incorporated by reference:

(1) Financial Statements

The financial statements filed as part of this Annual Report are listed in Index on page 49.

(2) Financial Statement Schedules

(3) Exhibits

The exhibits required by Item 601 of Regulation S-K are listed in subparagraph (b) below.

(b) Exhibits

(a) The exhibits marked with the asterisk symbol (*) are filed (or furnished in the case of Exhibits 32.1 and 32.2) with this Form 10-K. The exhibits marked with the cross symbol (†) are management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

86

Exhibit Number	Description	Originally Filed as Exhibit	File Number
3.1	Certificate of Incorporation of Energy XXI (Bermuda) Limited	3.1 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
3.2	Certificate of Incorporation on Change of Name of Energy XXI (Bermuda) Limited	3.2 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
3.3	Certificate of Deposit of Memorandum of Increase of Share Capital of Energy XXI (Bermuda) Limited	3.3 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
3.4	Altered Memorandum of Association of Energy XXI (Bermuda) Limited	3.4 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
3.5	Bye-Laws of Energy XXI (Bermuda) Limited	3.5 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
3.6	Amended Bye-Laws of Energy XXI (Bermuda) Limited	3.1 to Form 8-K filed November 15, 2007	1-33628
4.1	Investor Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) Limited, Sunrise Securities Corp. and Collins Steward Limited	4.1 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
4.2	Registration Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) and the investors named therein	4.2 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
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	4.3 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
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	10.1 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.2†	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and John D. Schiller, Jr.	10.2 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639

87

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.3†	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and Steve Weyel	10.3 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.4†	Employment Agreement dated April 4, 2006 between Energy XXI (Bermuda) Limited and David West Griffin	10.4 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.5†	2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.5 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.6†	Form of Restricted Stock Grant Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.6 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.7†	Form of Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.7 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.8†	Appointment letter dated August 31, 2005 for William Colvin	10.8 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.9†	Appointment letter dated August 31, 2005 for David Dunwoody	10.9 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.10†	Appointment letter dated April 16, 2007 for Hill Feinberg	10.10 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.11†	Appointment letter dated April 24, 2007 for Paul Davison	10.11 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.12	Letter Agreement dated September 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.	10.12 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.13	Assumption and Indemnity Agreement dated September 15, 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.	10.13 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
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	10.14 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639

88

Exhibit Number	Description	Originally Filed as Exhibit	File Number
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	10.15 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
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	10.16 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
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.	10.17 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
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	10.18 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
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	10.19 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
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	10.20 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.21	Participation Agreement dated as January 26, 2007 by and between Centurion Exploration Company and Energy XXI Gulf Coast, Inc.	10.21 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639

89

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.22	Purchase and Sale Agreement, dated as of April 24, 2007, by and between Pogo Producing Company and Energy XXI GOM, LLC	10.22 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
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	10.23 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.24†	2006 Long-Term Incentive Plan of Energy XXI Services, LLC (as amended for fiscal year 2008)	10.1 to Form S-8 filed on November 30, 2007	333-147731
10.25	First Amendment to the June 8, 2007 Amended and Restated First Lien Credit Agreement, dated November 19, 2007	10.1 to Form 8-K filed on November 26, 2007	001-33628
10.26	Second Amendment to the June 8, 2007 Amended and Restated First Lien Credit Agreement, dated December 1, 2008	10.1 to Form 8-K filed on December 15, 2008	001-33628
10.27	Third Amendment to the June 8, 2007 Amended and Restated First Lien Credit Agreement, dated April 6, 2009	10.1 to Form 8-K filed on March 31, 2009	001-33628
10.28†	Form of Notice of Grant of Stock Option together with Form of Stock Option Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.25 to Form 10-K filed on September 11, 2008	001-33628
10.29†	Energy XXI Services, LLC Directors’ Deferred Compensation Plan	10.1 to Form 8-K filed on September 10, 2008	001-33628
10.30†	Employment Agreement of John D. Schiller, Jr., effective September 10, 2008	10.1 to Form 8-K filed on September 11, 2008	001-33628
10.31†	Employment Agreement of Steve Weyel, effective September 10, 2008	10.2 to Form 8-K filed on September 11, 2008	001-33628
10.32†	Employment Agreement of David West Griffin, effective September 10, 2008	10.3 to Form 8-K filed on September 11, 2008	001-33628
10.33†	Form of Indemnification Agreement between Energy XXI (Bermuda) Limited and Indemnitees	10.1 to Form 8-K filed on November 5, 2008	001-33628
10.34†	Form of Indemnification Agreement Between Company Subsidiaries and Indemnitees	10.2 to Form 8-K filed on November 5, 2008	001-33628
10.35†	Energy XXI Services, LLC Employee Stock Purchase Plan	10.1 to Form 8-K filed on November 5, 2008	001-33628

90

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.36†	Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan	4.2 to Form S-8 filed on June 10, 2009	333-159868
12.1*	Ratio of Earnings to Fixed Charges —  Energy XXI Gulf Coast, Inc.
14.1	Code of Business Conduct and Ethics	14.1 to Form 10-K filed September 11, 2008	001-33628
21.1*	Subsidiary List
23.1*	Consent of UHY LLP
23.2*	Consent of Netherland, Sewell & Associates, Inc.
23.3*	Consent of Miller and Lents, Ltd.
23.4*	Consent of Ryder Scott Company, L.P.
31.1*	Rule 13a-14(a)/15d-14(a) Certification of the Chairman and Chief Executive Officer of Energy XXI (Bermuda) Limited
31.2*	Rule 13a-14(a)/15d-14(a) Certification of the Chief Financial Officer of Energy XXI (Bermuda) Limited
32.1*	Certification of the Chief Executive Officer under 18 U.S.C. § 1350
32.2*	Certification of the Chief Financial Officer under 18 U.S.C. § 1350

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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

Bbls	Barrels	MMBbls	Millions of Barrels
Mcf	Thousand Cubic Feet	MMcf	Million Cubic Feet
Bcf	Billion Cubic Feet	MMBtu	Million British Thermal Units
DD&A	Depreciation, Depletion and Amortization	BOE	Barrel of Oil Equivalent
MBbls	Thousands of Barrels	MBOE	Thousand Barrels of Oil Equivalent
MMBOE	Millions of Barrels of Oil Equivalent	MBOED	Thousand Barrels of Oil Equivalent per Day

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

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

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

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

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

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

Exploitation is drilling wells in areas proven to be productive.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Workover is the operations on a producing well to restore or increase production.

Zone is a stratigraphic interval containing one or more reservoirs.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ENERGY XXI (BERMUDA) LIMITED
	By /s/ John D. Schiller, Jr. John D. Schiller, Jr. Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Position	Date
/s/ John D. Schiller, Jr. John D. Schiller, Jr.	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)	September 4, 2009
/s/ Steven A. Weyel Steven A. Weyel	President, Chief Operating Officer and Director	September 4, 2009
/s/ David West Griffin David West Griffin	Chief Financial Officer and Director (Principal Financial Officer and Principal Accounting Officer)	September 4, 2009
/s/ William Colvin William Colvin	Director	September 4, 2009
/s/ Paul Davison Paul Davison	Director	September 4, 2009
/s/ David M. Dunwoody David M. Dunwoody	Director	September 4, 2009
/s/ Hill A. Feinberg Hill A. Feinberg	Director	September 4, 2009

94