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, 2010

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 $0.005 per share		The NASDAQ Stock Market LLC

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

7.25% Convertible Perpetual Preferred Stock, par value $0.001

 

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 $554,418,676 based on the closing sale price of $11.55 per share as reported on The NASDAQ Stock Market LLC on December 31, 2009, the last business day of the registrant’s most recently completed second fiscal quarter.

The number of shares of the registrant’s common stock outstanding on August 31, 2010, was 51,138,513.

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, 2010, are incorporated by reference into Part III of this Annual Report on Form 10-K.

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ENERGY XXI (BERMUDA) LIMITED

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		Page
GLOSSARY OF TERMS			1
PART I
Cautionary Statement Regarding Forward-Looking Statements			3
Item 1 Business			4
Item 1A Risk Factors			12
Item 1B Unresolved Staff Comments			29
Item 2 Properties			29
Item 3 Legal Proceedings			36
Item 4 (Removed and Reserved)			36
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			37
Item 6 Selected Financial Data			40
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations			43
Item 7A Quantitative and Qualitative Disclosures About Market Risk			61
Item 8 Financial Statements and Supplementary Data			63
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			101
Item 9A Controls and Procedures			101
Item 9B Other Information			101
PART III
Item 10 Directors, Executive Officers and Corporate Governance			102
Item 11 Executive Compensation			102
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			102
Item 13 Certain Relationships and Related Transactions, and Director Independence			102
Item 14 Principal Accounting Fees and Services			102
PART IV
Item 15 Exhibits, Financial Statement Schedules			103
Signatures			104

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GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this document:

Bbls		Standard barrel containing 42 U.S. gallons		MMBbls		One million Bbls
Mcf		One thousand cubic feet		MMcf		One million cubic feet
Btu		One British thermal unit		MMBtu		One million Btu
BOE		Barrel of oil equivalent		MBOE		One thousand BOEs
DD&A		Depreciation, Depletion and Amortization		MMBOE		One million BOEs

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

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 oil and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well, is acreage that is allocated or assignable to producing wells or wells capable of production. For a complete definition of developed oil and gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(6).

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.

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

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

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

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. For a complete definition of production costs, please refer to the Sec’s Regulation S-X, Rule 4-10(a)(20).

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 reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

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 oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For a complete definition of undeveloped oil and gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(31).

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

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

Zone is a stratigraphic interval containing one or more reservoirs.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those described in (1) Part I, “Item 1A. Risk Factors” and elsewhere in this report, (2) our reports and registration statements filed from time to time with the Securities and Exchange Commission (“SEC”) and (3) other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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PART I

Item 1. Business

Overview

We are an independent oil and natural gas exploration and production company with operations focused in the U.S. Gulf Coast and the Gulf of Mexico. Our business strategy includes: (i) acquiring oil and gas properties; (ii) exploiting our core assets to enhance production and ultimate recovery of reserves; and (iii) utilizing a portion of our capital program to explore the ultra-deep shelf for potential quantities of oil and gas. As of June 30, 2010, our estimated net proved reserves were 75.6 million BOE, of which 63% was oil and 70% was proved developed.

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 London Stock Exchange (“AIM”). On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market.

Since the beginning of 2006, we have completed four major acquisitions for aggregate cash consideration of approximately $1.4 billion. In February 2006, we acquired Marlin Energy, L.L.C. (“Marlin”) for total cash consideration of approximately $448.4 million. In June 2006, we acquired Louisiana Gulf Coast producing properties from affiliates of Castex Energy, Inc. (“Castex”) for approximately $311.2 million in cash (the “Castex Acquisition”). In June 2007, we purchased certain Gulf of Mexico shelf properties (the “Pogo Properties”) from Pogo Producing Company (the “Pogo Acquisition”) for approximately $415.1 million. In November 2009, we acquired certain Gulf of Mexico shelf oil and natural gas interests from MitEnergy Upstream LLC (“MitEnergy”), a subsidiary of Mitsui & Co., Ltd. for total cash consideration of $276.2 million (the “Mit Acquisition”). Our core properties at June 30, 2010 were comprised of the following:

Our average daily production for the year ended June 30, 2010 was 21.8 MBOE per day, of which 67.4% was oil while quarter ended June 30, 2010 production was 25.3 MBOE per day, of which approximately 68.4% was oil. We operate or have an interest in 287 producing wells in 51 producing fields. All of our properties are primarily located on the Louisiana Gulf Coast and in the Gulf of Mexico, with approximately 84% 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. As of June 30, 2010, approximately 80% of our proved reserves were on properties we operate.

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We intend to grow our reserve base through our drilling program and further strategic acquisitions of oil and natural gas properties. We believe the mature legacy fields on our acquired properties lend themselves well to our aggressive exploitation strategy. We have a seismic database covering approximately 3,900 square miles, primarily focused on our existing operations. We have identified approximately 100 drilling opportunities on our fields and anticipate drilling three wells in our ultra-deep shelf program that could materially increase our reserve base should it prove successful. Our Board of Directors have approved an initial fiscal 2011 capital budget, excluding any potential acquisition, but including abandonment costs, of approximately $250 million.

Derivative Activities

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

Segment and Geographic Information

We operate as one segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined by accounting standards related to disclosures about segments of an enterprise and related information. As discussed above, all of our properties are primarily located on the Gulf Coast and in the Gulf of Mexico. For additional information about our business, including related financial information, please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8 “Financial Statements and Supplementary Data.”

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 62%, 65% and 62% of our total oil and natural gas revenues during the years ended June 30, 2010, 2009 and 2008, 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. The principal competitive factors in the acquisition of oil and gas assets include the staff and data necessary to identify, evaluate and acquire such assets and the financial resources necessary to acquire and develop the assets. 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

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the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Business Strategy

Acquire Producing Assets.  Our acquisition strategy focuses on mature, producing assets that have a high percentage of oil and are largely operated. We target properties in the Gulf of Mexico and onshore Gulf Coast, our core geographic area of expertise, with a goal of identifying properties with remaining low risk upside which we believe can be achieved through operational enhancements. Since our formation in 2005, we have completed four major acquisitions, for total consideration of $1.4 billion to acquire 80.5 MMBOE of net proved reserves. In connection with our acquisitions, we generally enter into hedging arrangements to protect a portion of the acquisition economics.

Exploit and Explore Core Properties.  We intend to focus our efforts on exploitation of acquired properties through production optimization, infill drilling, and extensive field studies of the primary reservoirs. Our goal is to exploit the properties that we acquire to achieve at least a 20% increase in present value of the properties after acquisition. We will consider increasing hedges as we increase production to help protect our investment.

Explore the Ultra-Deep Shelf.  Using a portion of our exploration budget, we explore for reserves on the ultra-deep shelf (depths in excess of 25,000 feet and water depths of less than 150 feet) of the Gulf of Mexico, with each target we believe has potential for significant reserves. Including Davy Jones and Blackbeard West, the McMoRan-operated partnership (in which the company has various interests) has identified 15 sub-salt prospects in shallow water near existing infrastructure. The partnership’s near-term sub-salt-shelf drilling plans include the Blackbeard East and Lafitte exploratory wells and the delineation well at Davy Jones. We have participated in five wells to date with participations ranging from 14.1% to 20%. Of these wells, two are pending further evaluation and two are in process. We target to spend approximately 15% of our cash flow on these ultra deep opportunities.

Regulatory Matters

Generally.  Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

Regulations affecting production.  All of the jurisdictions in which we operate generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many jurisdictions impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. There is generally no regulation of wellhead prices or other, similar direct economic regulation of production, but there can be no assurance that this will remain true in the future.

In the event we conduct operations on federal, state or Indian oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”) or other relevant federal or state agencies.

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Regulations affecting sales.  The sales prices of oil, natural gas liquids, and natural gas are not presently regulated but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We do not believe that we will be affected by any such FERC action in a manner materially differently than other natural gas producers in our areas of operation.

The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. Interstate transportation rates for oil, natural gas liquids and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Market manipulation and market transparency regulations.  Under the Energy Policy Act of 2005 (“EP Act 2005”), FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity” in order to enforce the anti-market manipulation provisions in the EP Act 2005. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of natural gas, natural gas liquids, and crude oil, our gathering of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits, and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

FERC has issued certain market transparency rules pursuant to its EP Act 2005 authority, which may affect some or all of our operations. FERC issued a final rule in 2007, as amended by subsequent orders on rehearing (“Order 704”), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including natural gas producers, gatherers, processors, and marketers, to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices, as explained in the order. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704. In addition, on November 20, 2008, FERC issued a final rule pursuant to its EP Act 2005 authority regarding daily scheduled flows and capacity posting requirements, as amended by subsequent orders on rehearing (“Order 720”). Under Order 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three (3) calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day. Over the previous three calendar years, we have delivered, on average, less than 50 million MMBtu of gas, and therefore we believe that we are currently exempt from Order 720.

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Gathering regulations.  Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own certain natural gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, on-going litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts or the U.S. Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations may also be subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner materially differently than other companies in our areas of operation.

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 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:

We routinely obtain permits for our facilities and operations in accordance with these applicable laws and regulations on an ongoing basis. In response to the April 20, 2010 Deepwater Horizon incident and resulting oil spill in the Gulf of Mexico, the U.S. Bureau of Energy Management, Regulation and Enforcement (“BOEM,” formerly known as the Minerals Management Service) has imposed a moratorium, until November 30, 2010, on the drilling of new wells by floating drilling rigs and those rigs that use blowout preventers on the sea floor, and has imposed new safety requirements for all new wells. This moratorium and the new safety requirements are likely to delay the drilling of new wells and increase our well drilling costs.

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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. Our insurance coverage 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.

Securities Regulation

Enterprises that sell securities in public markets are subject to regulatory oversight by agencies such as the SEC and The Nasdaq Stock Market LLC (the “Nasdaq”). This regulatory oversight imposes the responsibility on us for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting, and ensuring that the financial statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in such submissions not misleading. Failure to comply with the rules and regulations of the SEC could subject our company to litigation from public or private plaintiffs. Failure to comply with the rules of the Nasdaq could result in the delisting of our common stock, which would have an adverse effect on the liquidity and market value of our common stock. Compliance with some of these regulations is costly and regulations are subject to change or reinterpretation.

Employees

We had 119 employees at June 30, 2010. At June 30, 2010, we had no employees represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are good.

Available Information

We file or furnish annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents we file with the SEC at www.sec.gov.

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 SEC.

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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.		51		Chairman and Chief Executive Officer		July 2005
David West Griffin		49		Chief Financial Officer		July 2005
Ben Marchive		63		Executive Vice President of Exploration and Production		April 2006
Stewart Lawrence		49		Vice President of Investor Relations and Communications		March 2007
Hugh A. Menown		52		Senior Vice President, Chief Accounting Officer and Chief Information Officer		May 2007
Steve Nelson		50		Vice President of Drilling and Production		April 2006
Todd Reid		47		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 30 years in the oil and gas industry. In addition to forming our company, Mr. Schiller served as: 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 from September 1998 to March 1999. 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 The Alley Theater and Escape Family Resource Center, which are charitable organizations. 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.

David West Griffin.  Mr. Griffin is our Chief Financial Officer and has been since our inception, with 25 years of finance experience. Prior to our inception, Mr. Griffin spent his time focusing on the formation of our 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 Executive Vice President of Exploration and Production. He has 31 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 14 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. During 2003 to 2006, Ben pursued personal interests. Ben joined our 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.

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Stewart Lawrence.  Mr. Lawrence joined us in March 2007 as our Vice President of Investor Relations and Communications and has 23 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, one of the largest U.S. independent oil and gas companies. 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 Senior Vice President, Chief Accounting Officer and Chief Information Officer. He has more than 30 years of experience in mergers and acquisitions, auditing and managerial finance. Mr. Menown has served with us since August 2006. For the first 7 months of 2006, Mr. Menown worked as an independent consultant in the energy industry. Prior to that time, from 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 7 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 27 years of experience in the oil and gas business. In April 2006, we hired him from Devon Energy, the largest U.S. independent oil and gas company, 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 18 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. From 1993 to 2003, he held various senior management positions with Duke Energy 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.

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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:

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:

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, 2010, we had face value of total indebtedness of $731.1 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:

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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 pursue 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 could be reduced upon the next re-determination 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, 2010, total outstanding borrowings under our revolving credit facility were $109.5 million and our current borrowing base was $350 million. We expect that the next determination of the borrowing base under our revolving credit facility will occur in the fall of 2010, if the new borrowing base is reduced, 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.

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

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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 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 could 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 recent 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 revolving credit facility because of the deterioration of the capital and credit markets and our borrowing base.

The recent 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 revolving credit facility to fund our capital expenditures and have relied on the capital markets to provide us with additional capital for large or exceptional transactions. A continuation or recurrence of the economic crisis could further reduce the demand for oil and natural gas and put downward pressure on the prices for oil and natural gas. Our current borrowing base under our revolving credit facility is $350 million.

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 redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. 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 recent credit crisis made it more 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 increased substantially while the availability of funds from those markets generally 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 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.

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 indentures governing our senior notes and second lien notes and our revolving credit facility do not fully prohibit us or our subsidiaries from doing so. At June 30, 2010, we and our subsidiary guarantors collectively had approximately:

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

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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 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:

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 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 indentures governing our senior notes and second lien notes and our revolving credit facility 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 indentures governing our senior notes and second lien notes and our revolving credit facility contains various covenants that limit our ability and the ability of our subsidiaries to, among other things:

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 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.

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 markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth.

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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, 2010 and July 31, 2010 ranged from a high of $86.84 to a low of $68.01 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2010 to July 31, 2010 ranged from a high of $6.01 to a low of $3.84. 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:

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, 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.

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We may be limited in our ability to book additional proved undeveloped reserves under the new SEC rules.

We have included in this report certain estimates of our proved reserves as of June 30, 2010 prepared in a manner consistent with our and our independent petroleum consultant’s interpretation of the new SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies. These new rules are effective for annual reporting periods ended on or after December 31, 2009. Included within these new SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped.

As of June 30, 2010, approximately 30.5% of our total proved reserves were undeveloped and approximately 24.5% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be developed or produced.

While we have plans or are in the process of developing plans for exploiting and producing a majority of our proved reserves, there can be no assurance that all of those reserves will ultimately be developed or produced. We are not the operator with respect to approximately 27.0% of our proved undeveloped reserves, so we may not be in a position to control the timing of all development activities. Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reserves will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.

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

High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years when compared to other regions in the United States. Typically, 50% of the reserves of properties in the Gulf of Mexico are depleted within three to four years. Due to high initial production rates, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from other producing reservoirs. The vast majority of our existing operations are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend 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.

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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.

Shallow water ultra-deep shelf wells may require equipment that may delay development and incur longer drilling times that may increase costs.

We are currently participating in the drilling of the shallow-water, ultra-deep shelf appraisal well Davy Jones #14 and a well on South Timbalier 144, also known as Blackbeard East and are awaiting long lead facility equipment on South Timbalier 168, formerly known as Blackbeard West. All of these projects have some of the same geological characteristics as deepwater prospects with a potential for significant reserves. The use of advanced drilling technologies involves a higher risk of technological failure and usually higher costs. In addition, there can be delays in completion due to the need to obtain equipment that must be special ordered.

Deepwater operations present special risks that may adversely affect the cost and timing of development.

Currently, we have minority, non-operated interests in three deepwater fields, Viosca Knoll 822/823, Viosca Knoll 821 and Viosca Knoll 1003. We may evaluate additional 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.

Recent events in the Gulf of Mexico may increase risks, costs and delays in our offshore operations.

The recent explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico, as well as the resulting oil spill, may lead to increased governmental regulation of our and our industry’s operations in a number of areas, including health and safety, environmental, and licensing, any of which could result in significantly increased costs or delays in our current and future drilling operations. For example, new legislation has been proposed which would revamp federal oversight of offshore drilling, set new safety standards for drilling equipment and well design, increase liability limits for offshore drilling companies and bar companies with lax safety records from obtaining federal leases, among other provisions. Other governmental responses may include deep-water drilling moratoria or other potentially major restrictions on drilling and production. We cannot predict with any certainty whether such regulation will be enacted or what form such regulation could take. Additionally, this event may lead to increased difficulties obtaining insurance coverage on economically manageable terms. Additional governmental regulation or tightening of the insurance markets could increase our costs, cause delays or have a material impact on our business, financial condition and results of operations.

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The current moratorium on the drilling of certain types of wells in offshore waters of the United States could adversely affect our ability to drill new wells in a timely manner.

In May, June and July of 2010, the U.S. Department of the Interior, acting through the BOEM, issued a series of Notices to Lessees (the “NTLs”) seeking to implement a six-month moratorium, until at least November 30, 2010, on the drilling of new wells in deep waters of the U.S. Gulf of Mexico. In addition, the NTLs ordered the operators of 33 deepwater wells that were being drilled to halt drilling and take steps to secure the affected wells. The NTLs provide for certain exceptions to the moratorium, including, among others, operations necessary to sustain reservoir pressure from producing wells and workover operations. The NTLs have been subject to a variety of court challenges by offshore drilling companies and other entities adversely affected by the moratorium, and there is some possibility that the moratorium may be invalidated. Even if the moratorium is invalidated, however, the BOEM has imposed numerous new safety requirements on the drilling of new wells in offshore waters and these new requirements have slowed the issuance of permits for new wells in shallow waters not subject to the moratorium. The NTLs are in response to the April 20, 2010 explosion and fire on the Deepwater Horizon and the resulting oil spill. While our three deepwater wells were not affected by the moratorium, we cannot predict the full impact of the incident and resulting moratorium on our operations. In addition, we cannot predict how the United States and other foreign governments or regulatory agencies will respond to the incident or whether changes in laws and regulations concerning operations in the Gulf of Mexico and other foreign regions offshore or more generally will be enacted. Significant changes in regulations regarding future exploration and production activities in the Gulf of Mexico and other foreign regions offshore or other government or regulatory actions could reduce drilling and production activity, or increase the costs of drilling new wells, which could have a material adverse impact on our business.

Legislative and regulatory initiatives relating to offshore operations, which include consideration of increases in the minimum levels of demonstrated financial responsibility required to conduct exploration and production operations on the outer continental shelf and elimination of liability limitations on damages, will, if adopted, likely result in increased costs and additional operating restrictions and could have a material adverse effect on our business.

The Oil Pollution Act of 1990 (the “OPA”) and regulations adopted pursuant to the OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States. The OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. The OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the Outer Continental Shelf, although the Secretary of Interior may increase this amount up to $150 million in certain situations. The OPA also currently limits the liability of a responsible party for economic damages, excluding all oil spill response costs, to $75 million, although this limit does not apply if a federal safety, construction or operating regulation was violated. The states in which we operate have also adopted similar laws and regulations relating to offshore operations in their waters. The United States Congress is currently considering a variety of amendments to the OPA in response to the recent Deepwater Horizon incident in the Gulf of Mexico, including an increase in the minimum level of financial responsibility, an elimination of all liability limitations on damages, and enhancements to safety and spill-response requirements. Additional state regulation in these areas is also possible. Any new requirements would likely increase the cost of operations for our offshore activities, including insurance costs, and expose us to increased liability, which could have an adverse effect on our results of operations. If we are unable to satisfy new legislative and regulatory requirements, we may be required to curtail operations, sell our offshore properties or operations, or enter into partnerships with other companies that can meet the new requirements, which may have an adverse effect on the value of our offshore assets and the results of our operations. While we believe that we currently are in compliance with the OPA, we cannot predict at this time whether the OPA will be amended or new state regulations adopted, what the substance of any such amendment or regulations will be or what impact any such amendments might

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have on our operations. In addition, our costs could also increase for our onshore operations due to changes in standard industry practices in anticipation of, or in reaction to, any new offshore regulation.

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. Prior to June 30, 2010, future net cash flows were based on period-end commodity prices and excluded future cash outflows related to estimated abandonment costs of proved developed properties. Effective with our June 30, 2010 financial statements, prices are based on the average realized prices for the previous twelve-month period. 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 the average previous twelve-month 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, these higher hedged prices are used if they qualify as cash flow hedges.

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. Bureau of Energy Management, Regulation and Enforcement (“BOEM”, formerly known as the Minerals Management Service), which, if required, could be costly and reduce borrowings available under our bank credit facility.

For offshore operations, lessees must comply with the BOEM 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. The BOEM’s safety requirements have recently been made more stringent as a result of the April 20, 2010 Deep Water Horizon incident and resulting oil spill in the Gulf of Mexico. To cover the various obligations of lessees on the U.S. Outer Continental Shelf of the Gulf of Mexico, the BOEM generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. While we believe that we are currently exempt from the supplemental bonding requirements of the BOEM, the BOEM could re-evaluate our plugging obligations and increase them which could cause us to lose our exemption. 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 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.

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

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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, Hurricanes Ivan, Katrina, Rita, Gustav and Ike, and the April 20, 2010 Deep Water Horizon incident, 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. In addition, 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 vendor, 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.

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 BOEM 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 average prices for the preceding twelve-month period 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:

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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:

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:

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

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, market access 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. Restrictions on our ability to sell our oil and natural gas may have several other adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possible loss of a lease due to lack of production. In the event that we encounter restrictions in our ability to tie our production to a gathering system, we may face considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.

We 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 80% 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:

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

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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.

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

Our oil and gas exploration, production, and related operations are subject to extensive rules and regulations promulgated by federal, state, and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

All of the jurisdictions in which we operate generally require permits for drilling operations, drilling bonds, and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain jurisdictions also limit the rate at which oil and gas can be produced from our properties.

The FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

Our sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Under the EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting and daily scheduled flow and capacity posting requirements, as described more fully in Item 1 above. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

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:

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

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.

Our sales of oil and natural gas, and any hedging activities related to such energy commodities, expose us to potential regulatory risks.

The FERC, the Federal Trade Commission and the Commodity Futures Trading Commission hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these energy commodities, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas we produce while the physical effects of climate change could disrupt our production and cause us to incur costs in preparing for or responding to those effects.

On December 15, 2009, the U.S. Environmental Protection Agency, or “EPA” published its final findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. In March 2010, the EPA announced a

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proposed rulemaking that would expand its final rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems. If the proposed rule is finalized in its current form, monitoring of those newly covered sources would commence on January 1, 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Further, Congress is presently considering, and almost one-half of the states have adopted, legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Any such legislation could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations and cause us to incur costs in preparing for or responding to those effects.

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

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material effect on our financial condition and our results of operations.

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 four 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:

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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.

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.

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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:

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.

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 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.

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

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

The 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, 2010 represent approximately 80% of our net proved reserves and 87% of our future net revenues, discounted at 10%.

General Information on Properties

Main Pass 61 Field.  We operate and have a 100% working interest in the Main Pass 61 field, located near the mouth of the Mississippi River in approximately 90 feet of water on Outer Continental Shelf (“OCS”) blocks Main Pass 60, 61, 62 and 63. The field was discovered by Pogo in 2000, and has produced in excess of 45 MMBOE since production first began in 2002, from four Upper Miocene sands. The primary producer is the J-6 Sand, which consists of a series of stratigraphic traps, located along regional south dip, in a normal pressure environment. The two larger J-6 Sand stratigraphic pods are black oil reservoirs that are being waterflooded to maximize recovery. There are 20 producing wells and three major production platforms

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located throughout the field. Since acquiring the field in mid 2007, Energy XXI has drilled five wells and two sidetracks, performed two rig recompletions, and added acreage via the OCS lease sale. The field’s average net production for the quarter ended June 30, 2010 of 7.5 MBOED, accounting for approximately 30% of our net production for the quarter. Net proved reserves for the field, which is our largest, were 89% oil.

South Timbalier 21 Field.  We operate and have a 100% 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 10 major production platforms and 61 smaller structures located throughout the field. Since acquiring the field in June 1, 2006, implemented field projects include 19 drill wells and 15 rig workovers in this field. The field’s average net production for the quarter ended June 30, 2010 was 4.1 MBOED, accounting for approximately 16% of our net production for the quarter. Net proved reserves for the field, which is our second largest, were 76% oil.

Viosca Knoll 1003 Field.  Viosca Knoll 1003 field, which is operated by Newfield Exploration is located in 4,482 feet of water and is a one-well field development completed in the Tex W Sand where we have a working interest in the field is 33.3%. The well is a subsea tie-back to Viosca Knoll 823 (Virgo Field) located 19.6 miles away and our net proved reserves at June 30, 2010 were 51% oil. First production began in October 2009 and the field’s average net production for the quarter ended June 30, 2010 was 2.7 MBOED.

South Pass 49 Field.  We have a 100% working interest in and operate the South Pass 49 field Unit which is located near the mouth of the Mississippi River in approximately 300 feet of water. The field produces from Lower Pliocene sands which 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 57% working interest in and operate all sands located at depths above and below the D69/D70 unit. The field is produced from one central production platform, which was shut in throughout 2009 due to damage sustained to the sales pipelines during Hurricane Gustav in late 2008 and returned back online in February 2010. The field’s average net production for the quarter ended June 30, 2010 was 1.9 MBOED. Net proved reserves for the field were 51% oil.

Main Pass 73/74 Field.  We have a 100% working interest 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 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 gas-condensate wells on Main Pass 74. Average net production from the complex for the quarter ended June 30, 2010 was 1.1 MBOED (MP 72/73 was offline 10 weeks due to a damaged sales pipeline). Net proved reserves for the field were 67% oil.

East Cameron 334 Field.  We operate and have a 72% working interest in the East Cameron 334 Field located 90 miles South of Cameron, Louisiana in 230 feet of water. The field underlies East Cameron Blocks 334, 335, 336 and West Cameron 580 and 601. Discovered in 1972, this is the 29th 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. The field had been shut-in since August 2008 due to damage that was sustained by Hurricane Gustav and production was restored during February 2010. The field’s average net production for the quarter ended June 30, 2010 was 0.6 MBOED. Net proved reserves were 87% natural gas.

Eugene Island 330 Field.  We have a 35% 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. 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 damaged by Hurricane Ike and salvage of the platforms which is

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underway. Production from the 10 remaining wells in the field were restored by Apache in late 2009. The field’s average net production for the quarter ended June 30, 2010 was 0.6 MBOED. Net reserves are 82% oil.

Cote de Mer Field.  We have a 32.8% working interest in this field and are the operator of this field which is located onshore South Louisiana. The discovery well was drilled to 22,261 feet in March 2009. First production started in our fiscal second quarter. The field’s average net production for the quarter ended June 30, 2010 was 0.2 MBOED. Net proved reserves were 98% natural gas.

Reserve Rule Changes

In December 2008, the SEC issued its final rule on the modernization of oil and gas reporting (the “Reserve Ruling”) and the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2010-03 (“ASU 2010-03”) “Extractive Industries — Oil and Gas,” which aligns the estimation and disclosure requirements of FASB Accounting Standards Codification Topic 932 with the Reserve Ruling. The Reserve Ruling and ASU 2010-03 are effective for Annual Reports on Form 10-K for fiscal years ending on or after December 31, 2009. We adopted the new rules effective June 30, 2010. The new rules are applied prospectively as a change in estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.

The key provisions of the Reserve Ruling and ASU 2010-03 are as follows:

Reserve Estimation Procedures and Audits

The information included in this Annual Report on Form 10-K about our proved reserves represents evaluations prepared by our in-house reserve engineers as well as Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”). NSAI has prepared evaluations on 87 percent of our proved reserves on a valuation basis, the remainder, prepared by our engineers, and the estimates of proved crude oil and natural gas reserves attributable to our net interests in oil and gas properties as of June 30, 2010. The scope and results of NSAI’s procedures are summarized in a letter which is included as an exhibit to this Annual Report on Form 10-K. 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.”

Internal Controls for Reserve Estimation

The reserve estimates prepared by NSAI are reviewed and approved by members of our senior engineering staff and management. The process performed by NSAI to prepare reserve amounts included the estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue. NSAI also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance. In the conduct of their preparation of the reserve estimates, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any

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agreements relating to current and future operations of the properties and sales of production. However, if in the course of its work, something came to its attention which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.

Technologies Used in Reserves Estimates

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our independent petroleum consultant employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.

Qualifications of Reserves Preparers and Auditors

We are staffed by petroleum engineers with extensive industry experience who meet the professional qualifications of reserves estimators and reserves auditors as defined by the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” approved by the Board of the Society of Petroleum Engineers in 2001 and revised in 2007.

Our Vice President of Corporate Development, Tom O’Donnell, is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for the coordination of the third-party reserve report provided by Netherland, Sewell, and Associates. Mr. O’Donnell has over 24 years of experience and is a graduate of Texas A&M University with a Bachelor of Science degree in Petroleum Engineering. He is a member of the Society of Petroleum Engineers and is a Registered Professional Engineer in the state of Texas. Prior to joining Energy XXI in 2006, Mr. O’Donnell held engineering and managerial positions with Burlington Resources and Mobil Oil Corporation.

NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. The technical person primarily responsible for the preparation of our reserves estimates has been a practicing consulting petroleum engineer at NSAI since 2006 and has over 9 years of practical experience in petroleum engineering. He graduated with a Bachelor of Science in Petroleum Engineering and meets or exceeds the education, training, and experience requirements set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.” The technical work was conducted by a team of six NSAI petroleum engineers and geoscientists having an average industry experience of 20 years.

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Summary of Oil and Gas Reserves at June 30, 2010

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 (87 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.

		Summary of Oil and Gas Reserves as of June 30, 2010 Based on Averaged Fiscal-Year Prices
		Oil (MBbls)				Natural Gas (MMcf)				MBOE				PV-10 (in thousands)(1)
Proved
Developed			36,970				93,670				52,572			$	1,481,816
Undeveloped			10,513				75,173				23,042			$	367,100
Total Proved			47,483				168,783				75,614			$	1,848,916

Changes in Proved Reserves

Our total proved reserves increased 22.5 MMBOE from 53.1 MMBOE at June 30, 2009 to 75.6 MMBOE at June 30, 2010, primarily attributable to the Mit Acquisition.

The adoption of the new SEC rules related to modernizing reserve estimation and disclosure requirements did not materially affect our total proved reserves.

Development of Proved Undeveloped Reserves

Our proved undeveloped reserves at June 30, 2010 were 23.0 MMBOE. Future development costs associated with our proved undeveloped reserves at June 30, 2010 totaled approximately $399.1 million. In the fiscal year ended June 30, 2010, we developed approximately 21% of our proved undeveloped reserves as of June 30, 2009, consisting of 3 gross 1.5 net wells at a net cost of approximately $10.1 million. None of our proved undeveloped well locations remain undeveloped past 5 years from the date of initial recognition as proved undeveloped.

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Drilling Activity

The following table sets forth our drilling activity.

		Year Ended June 30,
		2010								2009								2008
		Gross				Net				Gross				Net				Gross				Net
Productive wells drilled
Development			3.0				1.5				7.0				3.7				8.0				5.4
Exploratory			3.0				0.6				2.0				0.6				6.0				2.0
Total			6.0				2.1				9.0				4.3				14.0				7.4
Non productive dry wells drilled
Development			1.0				1.0				—				—				2.0				2.0
Exploratory			3.0				1.6				6.0				3.5				12.0				5.0
Total			4.0				2.6				6.0				3.5				14.0				7.0

Present Activities

As of June 30, 2010, four gross wells, representing approximately 1.1 net wells, were being drilled which include the ultra-deep shelf appraisal well Davy Jones #14 and the well on South Timbalier 144, also known as Blackbeard East. The LL&E 237 was drilled in the Golden Meadow field as an exploratory well by Apache Corporation in Lafourche Parish, Louisiana. The well went on production in April 2010 and produced 25.3 net MBOE during the fiscal year ended June 30, 2010.

Delivery Commitments

As of June 30, 2010, we had no delivery commitments.

Productive Wells

Our working interests in productive wells follow.

		June 30,
		2010								2009
		Gross				Net				Gross				Net
Natural Gas			118				38.7				127				38.1
Crude Oil			169				105.9				147				72.5
Total			287				144.6				274				110.6

Acreage

Working interests in developed and undeveloped acreage follow.

		June 30, 2010
		Developed Acres								Undeveloped Acres								Total Acres
		Gross				Net				Gross				Net				Gross				Net
Onshore			95,597				57,539				16,240				7,309				111,837				64,848
Offshore			284,282				114,181				85,828				44,231				370,110				158,412
Total			379,879				171,720				102,068				51,540				481,947				223,260

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

		Year Ended June 30,
		2011								2012								2013
		Gross				Net				Gross				Net				Gross				Net
Onshore			5,908				3,112				3,098				1,284				1,746				518
Offshore			5,420				763				—				—				29,186				17,125
Total			11,328				3,875				3,098				1,284				30,932				17,643

Capital Expenditures, Including Acquisitions and Costs Incurred

Property acquisition costs:

		Year Ended June 30,
		2010				2009				2008
		(In Thousands)
Oil and Gas Activities
Development		$	92,949			$	142,848			$	232,776
Exploration			51,030				121,554				114,639
Acquisitions			293,037				—				40,016
Administrative and other			1,133				1,610				9,758
Capital expenditures, including acquisitions			438,149				266,012				397,189
Asset retirement obligations, insurance proceeds and other, net			17,996				71,788				(13,321	)
Total costs incurred		$	456,145			$	337,800			$	383,868

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,
		2010				2009				2008
Sales Volumes per Day
Natural gas (MMcf)			42.6				47.9				75.7
Crude oil (MBbls)			14.7				11.4				13.5
Total (MBOE)			21.8				19.3				26.2
Percent of BOE from crude oil			67.4	%			59.1	%			51.5	%
Average Sales Price
Natural gas per Mcf		$	4.47			$	6.48			$	8.57
Hedge gain per Mcf			2.68				1.60				0.34
Total natural gas per Mcf		$	7.15			$	8.08			$	8.91
Crude oil per Bbl		$	71.73			$	67.06			$	97.72
Hedge gain (loss) per Bbl			0.75				3.56				(17.82	)
Total crude oil per Bbl		$	72.48			$	70.62			$	79.90
Sales price per BOE		$	57.09			$	55.43			$	75.40
Hedge gain (loss) per BOE			5.74				6.04				(8.24	)
Total sales price per BOE		$	62.83			$	61.47			$	67.16

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Oil and Gas Production, Prices and Production Costs — Significant Fields

The following fields each contain 15% or more of our total proved reserves as of June 30, 2010. Our average daily production, average sales prices and production cost follow.

		Year Ended June 30,
		2010				2009				2008
Main Pass 61
Sales Volumes per Day
Natural gas (MMcf)			3.5				2.7				1.5
Crude oil (MBbls)			5.8				3.6				3.1
Total (MBOE)			6.4				4.1				3.4
Percent of BOE from crude oil			90.6	%			87.8	%			91.2	%
Average Sales Price
Natural gas per Mcf		$	4.99			$	6.71			$	8.72
Crude oil per Bbl		$	75.37			$	64.31			$	100.73
Production Cost per BOE		$	11.37			$	7.82			$	13.11
South Timbalier 21
Sales Volumes per Day
Natural gas (MMcf)			4.6				9.1				10.1
Crude oil (MBbls)			3.8				4.2				6.1
Total (MBOE)			4.6				5.7				7.8
Percent of BOE from crude oil			82.6	%			73.7	%			78.2	%
Average Sales Price
Natural gas per Mcf		$	4.23			$	6.14			$	9.47
Crude oil per Bbl		$	72.92			$	65.96			$	97.91
Production Cost per BOE		$	27.21			$	26.22			$	14.76

Production Unit Costs

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

		Year Ended June 30,
		2010				2009				2008
Average Costs per BOE
Production costs
Lease operating expense
Insurance expense		$	3.48			$	2.72			$	1.90
Workover and maintenance			2.47				2.26				2.34
Direct lease operating expense			12.01				12.33				10.68
Total lease operating expense			17.96				17.31				14.92
Production taxes			0.53				0.77				0.91
Total production costs		$	18.49			$	18.08			$	15.83
Depreciation, depletion and amortization rates		$	22.87			$	30.78			$	32.09

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. (Removed and Reserved)

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PART II

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

Market Information for Common Stock and Restricted Stock

Our restricted common stock trades on the London Stock Exchange AIM (“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 common stock as reported on the AIM Exchange and unrestricted common stock as reported on The NASDAQ Capital Market.

		Restricted Common Stock								Unrestricted Common Stock
		High				Low				High				Low
Fiscal 2009
First Quarter		$	29.50			$	16.90			$	32.95			$	13.90
Second Quarter			16.25				4.40				14.40				3.35
Third Quarter			5.25				2.40				6.25				1.40
Fourth Quarter			2.40				0.50				3.80				2.05
Fiscal 2010
First Quarter			9.50				2.38				9.45				2.25
Second Quarter			25.00				0.50				12.35				7.10
Third Quarter			19.50				5.00				20.85				12.35
Fourth Quarter			19.50				15.50				22.38				13.48

As of August 31, 2010, there were approximately 240 holders of record of our unrestricted common stock.

As of August 31, 2010, there were approximately 55 holders of record of our restricted common stock.

Dividend Information

On September 9, 2008, the Board of Directors (“Board”) declared a common stock quarterly cash dividend of $0.025 per share, payable October 20, 2008 to shareholders of record on September 19, 2008. On November 3, 2008, the Board declared a cash dividend of $0.025 per common share, payable on December 5, 2008 to shareholders of record on November 14, 2008. On February 6, 2009, the Board declared a cash dividend of $0.025 per common share, payable on March 13, 2009 to shareholders of record on February 20, 2009.

Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

The following table provides information about purchases of equity securities that are registered by us pursuant to Section 12 of the Exchange Act during the year ended June 30, 2010:

Period		Total Number of Shares Purchased				Average Price Paid Per Share				Total Number of Shares Purchased as Part of a Publicly Announced Plans or Programs				Maximum Number or Approximate Dollar Value that May Yet be Purchased Under the Plans or Programs
July 1 – July 31, 2009			156,119			$	2.90				—				—
February 1 – February 28, 2010			200,377			$	19.64				—				—

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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 XOI Index, the SPX Index and the RAY Index. This chart represents our freely tradable unrestricted shares from December 31, 2005 through August 30, 2010.

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 XOI Index, the SPX Index and the RAY 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 – EXXI US Equity		$	100.00			$	107.99			$	97.12			$	86.54			$	93.27			$	108.85			$	122.69
AMEX Oil Index – XOI Index		$	100.00			$	108.48			$	116.88			$	109.83			$	120.40			$	123.25			$	142.87
S&P 500 – SPX Index		$	100.00			$	103.73			$	101.76			$	107.01			$	113.62			$	113.82			$	120.43
Russell 3000 – Ray Index		$	100.00			$	104.86			$	102.33			$	106.60			$	113.66			$	114.62			$	120.72

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		Initial Investment				Cumulative Total Return
						Q1-08				Q2-08				Q3-08				Q4-08				Q1-09				Q2-09
EXXI – EXXI US Equity		$	100.00			$	101.92			$	99.23			$	74.42			$	133.07			$	58.46			$	15.19
AMEX Oil Index – XOI Index		$	100.00			$	145.94			$	158.01			$	135.55			$	155.59			$	117.17			$	99.28
S&P 500 – SPX Index		$	100.00			$	122.31			$	117.63			$	105.96			$	105.54			$	93.44			$	72.36
Russell 3000 – Ray Index		$	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				Q2-10				Q3-10				Q4-10
EXXI – EXXI US Equity		$	100.00			$	7.21			$	9.93			$	29.81			$	44.42			$	68.88			$	60.69
AMEX Oil Index – XOI Index		$	100.00			$	86.24			$	93.12			$	103.81			$	108.25			$	109.56			$	89.54
S&P 500 – SPX Index		$	100.00			$	63.92			$	73.65			$	84.68			$	89.33			$	93.68			$	82.57
Russell 3000 – Ray Index		$	100.00			$	63.75			$	74.05			$	85.70			$	90.30			$	95.22			$	84.05

		Initial Investment				Cumulative Total Return
						Q1-11(1)
EXXI – EXXI US Equity		$	100.00			$	76.27
AMEX Oil Index – XOI Index		$	100.00			$	94.08
S&P 500 – SPX Index		$	100.00			$	84.03
Russell 3000 – Ray Index		$	100.00			$	85.34

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Item 6. Selected Financial Data

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

		Year Ended June 30,																Period from Inception July 25, 2005 Through June 30, 2006
		2010				2009				2008				2007
		(In Thousands, Except per Share Amounts)
Income Statement Data
Revenues		$	498,931			$	433,830			$	643,232			$	341,284			$	47,112
Depreciation, Depletion and Amortization (“DD&A”)			181,640				217,207				307,389				145,928				20,357
Impairment of Oil and Gas Properties			—				576,996				—				—				—
Operating Income (Loss)			102,047				(517,217	)			143,600				95,215				11,602
Other Income (Expense) – Net			(58,483	)			(76,751	)			(101,857	)			(58,420	)			(2,933	)
Net Income (Loss)			27,320				(571,629	)			26,869				24,130				6,942
Basic Earnings (Loss) per Common Share		$	0.56			$	(19.77	)		$	1.57			$	1.45			$	0.70
Diluted Earnings (Loss) per Common Share		$	0.56			$	(19.77	)		$	1.49			$	1.45			$	0.60
Cash Flows Data
Provided by (Used in)
Operating Activities		$	121,213			$	245,835			$	414,647			$	270,783			$	12,068
Investing Activities
Acquisitions			(293,037	)			—				(40,016	)			(717,618	)			(448,374	)
Investment in properties			(145,112	)			(266,012	)			(357,173	)			(427,213	)			(19,703	)
Other			53,989				2,935				(296	)			1,955				(12,593	)
Total Investing Activities			(384,160	)			(263,077	)			(397,485	)			(1,142,876	)			(480,670	)
Financing Activities			188,246				(62,795	)			132,016				829,488				530,991
Increase (Decrease) in Cash		$	(74,701	)		$	(80,037	)		$	149,178			$	(42,605	)		$	62,389
Dividends Paid per Average Common Share			—			$	0.075				—				—				—

		June 30,
		2010				2009				2008				2007				2006
		(In Thousands)
Balance Sheet Data
Total Assets		$	1,566,491			$	1,328,662			$	2,049,931			$	1,648,442			$	643,971
Long-term Debt Including Current Maturities			774,600				862,827				952,222				1,051,019				209,648
Stockholders’ Equity			436,561				127,500				374,585				397,126				352,709
Common Shares Outstanding			50,637				29,150				28,987				16,840				16,129

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		Year Ended June 30,																Period from Inception July 25, 2005 Through June 30, 2006
Operating Highlights		2010				2009				2008				2007
		(In Thousands, Except per Unit Amounts)
Operating revenues
Crude oil sales		$	383,928			$	278,014			$	484,552			$	177,783			$	29,751
Natural gas sales			69,399				113,156				237,628				131,065				15,934
Hedge gain (loss)			45,604				42,660				(78,948	)			32,436				1,427
Total revenues			498,931				433,830				643,232				341,284				47,112
Percent of operating revenues from crude oil
Prior to hedge gain (loss)			84.7	%			71.1	%			67.1	%			57.6	%			67.3	%
Including hedge gain (loss)			77.8	%			67.5	%			61.6	%			56.8	%			62.0	%
Operating expenses
Lease operating expense
Insurance expense			27,603				19,188				18,218				12,670				144
Workover and maintenance			19,630				15,930				22,397				8,269				166
Direct lease operating expense			95,379				87,032				102,244				48,046				9,592
Total lease operating expense			142,612				122,150				142,859				68,985				9,902
Production taxes			4,217				5,450				8,686				3,595				84
Depreciation, depletion and amortization			181,640				217,207				307,389				145,928				20,357
Impairment of oil and gas properties			—				576,996				—				—				—
General and administrative			49,667				24,756				26,450				26,507				4,361
Other – net			18,748				4,488				14,248				1,054				806
Total operating expenses			396,884				951,047				499,632				246,069				35,510
Operating income (loss)		$	102,047			$	(517,217	)		$	143,600			$	95,215			$	11,602
Sales volumes per day
Natural gas (MMcf)			42.6				47.9				75.7				50.3				27.9
Crude oil (MBbls)			14.7				11.4				13.5				7.8				5.1
Total (MBOE)			21.8				19.3				26.2				16.2				9.7
Percent of sales volumes from crude oil			67.4	%			58.7	%			51.8	%			48.2	%			52.1	%
Average sales price
Natural gas per Mcf		$	4.47			$	6.48			$	8.57			$	7.13			$	6.48
Hedge gain per Mcf			2.68				1.60				0.34				0.90				0.86
Total natural gas per Mcf		$	7.15			$	8.08			$	8.91			$	8.03			$	7.34
Crude oil per Bbl		$	71.73			$	67.06			$	97.72			$	62.33			$	66.64
Hedge gain (loss) per Bbl			0.75				3.56				(17.82	)			5.60				(1.56	)
Total crude oil per Bbl		$	72.48			$	70.62			$	79.90			$	67.93			$	65.08
Total hedge gain (loss) per BOE		$	5.74			$	6.04			$	(8.24	)		$	5.48			$	1.67
Operating revenues per BOE		$	62.83			$	61.47			$	67.16			$	57.71			$	55.02
Operating expenses per BOE
Lease operating expense
Insurance expense			3.48				2.72				1.90				2.14				0.17
Workover and maintenance			2.47				2.26				2.34				1.40				0.19
Direct lease operating expense			12.01				12.33				10.68				8.12				11.20
Total lease operating expense			17.96				17.31				14.92				11.66				11.56
Production taxes			0.53				0.77				0.91				0.61				0.10
Impairment of oil and gas properties			—				81.75				—				—				—
Depreciation, depletion and amortization			22.87				30.78				32.09				24.68				23.78
General and administrative			6.25				3.51				2.76				4.48				5.09
Other – net			2.36				0.64				1.49				0.18				0.94
Total operating expenses			49.97				134.76				52.17				41.61				41.47
Operating income (loss) per BOE		$	12.86			$	(73.29	)		$	14.99			$	16.10			$	13.55

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		Quarter Ended
Quarterly Highlights		June 30, 2010				Mar. 31, 2010				Dec. 31, 2009				Sept. 30, 2009				June 30, 2009
		(In Thousands, Except per Unit Amounts)
Operating revenues
Crude oil sales		$	113,908			$	117,932			$	93,974			$	58,114			$	58,920
Natural gas sales			19,945				22,872				16,812				9,770				15,168
Hedge gain			5,538				9,323				13,720				17,023				27,010
Total revenues			139,391				150,127				124,506				84,907				101,098
Percent of operating revenues from crude oil
Prior to hedge gain			85.1	%			83.8	%			84.8	%			85.6	%			79.5	%
Including hedge gain			78.6	%			76.0	%			78.8	%			78.1	%			70.8	%
Operating expenses
Lease operating expense
Insurance expense			7,220				6,602				7,827				5,954				4,356
Workover and maintenance			5,269				8,452				2,678				3,231				4,622
Direct lease operating expense			28,816				25,778				24,545				16,240				15,646
Total lease operating expense			41,305				40,832				35,050				25,425				24,624
Production taxes			1,065				870				1,007				1,275				(51	)
DD&A			50,556				50,761				44,972				35,351				39,744
General and administrative			13,127				14,452				14,022				8,066				6,168
Other – net			5,116				6,649				8,116				(1,133	)			3,852
Total operating expenses			111,169				113,564				103,167				68,984				74,337
Operating income		$	28,222			$	35,563			$	21,339			$	15,923			$	26,761
Sales volumes per day
Natural gas (MMcf)			48.2				48.4				40.7				33.2				41.1
Crude oil (MBbls)			17.3				17.3				14.2				10.0				11.9
Total (MBOE)			25.3				25.4				20.9				15.5				18.7
Percent of sales volumes from crude oil			68.4	%			68.3	%			67.6	%			64.5	%			63.6	%
Average sales price
Natural gas per Mcf		$	4.55			$	5.25			$	4.49			$	3.20			$	4.06
Hedge gain per Mcf			2.27				3.03				2.58				2.90				3.85
Total natural gas per Mcf		$	6.82			$	8.28			$	7.07			$	6.10			$	7.91
Crude oil per Bbl		$	72.42			$	75.54			$	72.17			$	63.44			$	54.56
Hedge gain (loss) per Bbl			(2.80	)			(2.46	)			3.13				8.93				11.68
Total crude oil per Bbl		$	69.62			$	73.08			$	75.30			$	72.37			$	66.24
Total hedge gain per BOE		$	2.40			$	4.08			$	7.12			$	11.95			$	15.86
Operating revenues per BOE		$	60.50			$	65.65			$	64.65			$	59.59			$	59.36
Operating expenses per BOE
Lease operating expense
Insurance expense			3.13				2.89				4.06				4.18				2.56
Workover and maintenance			2.29				3.70				1.39				2.27				2.71
Direct lease operating expense			12.51				11.27				12.74				11.40				9.19
Total lease operating expense			17.93				17.86				18.19				17.85				14.46
Production taxes			0.46				0.38				0.52				0.89				(0.03	)
DD&A			21.94				22.20				23.35				24.81				23.34
General and administrative			5.70				6.32				7.28				5.66				3.62
Other – net			2.22				2.91				4.22				(0.80	)			2.27
Total operating expenses			48.25				49.67				53.56				48.41				43.66
Operating income (loss) per BOE		$	12.25			$	15.98			$	11.09			$	11.18			$	15.70

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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 with properties focused in the U.S. Gulf Coast and the Gulf of Mexico. Our business strategy includes: (i) acquiring oil and gas properties; (ii) exploiting our core assets to enhance production and ultimate recover of reserves; and (iii) utilizing a portion of our capital program to explore the ultra-deep shelf for large potential quantities of oil and gas.

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, 2010, approximately 76% of our capital expenditures were associated with the exploitation of existing properties less acquisitions. During the past three 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 and MitEnergy on November 23, 2009. For the quarter ended June 30, 2010, production from those properties averaged over fifteen thousand barrels of oil equivalent per day (“MBOED”).

At June 30, 2010, our total proved reserves were 75.6 million barrels of oil equivalent (“MMBOE”) of which 63% were oil and 70% were classified as proved developed. We operated or had an interest in 287 producing wells on 171,720 net developed acres, including interests in 51 producing fields. All of our properties are primarily located on the Gulf Coast and in the Gulf of Mexico, with approximately 84% 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 80% of our proved reserves are on properties operated by us. We have a seismic database covering approximately 3,900 square miles, primarily focused on our existing operations. This database has helped us identify approximately 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% 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 one percent to the general partner and 99% to the limited partners. The Partnership was formed to acquire certain onshore southern Louisiana assets from EPL of Louisiana, L.L.C. effective April 1, 2007 for consideration of $71.7 million. We were distributed our proportionate share of the Partnership assets and liabilities effective November 30, 2007.

Mit Acquisition.  On December 22, 2009, we closed on the acquisition of certain Gulf of Mexico shelf oil and natural gas interests from MitEnergy Upstream LLC, a subsidiary of Mitsui & Co., Ltd. (the “Mit Acquisition”), for cash consideration of $276.2 million. The Mit Acquisition involves mirror-image non-operated interests in the same group of properties we purchased from Pogo Producing Company in June 2007. These properties include 30 fields of which production is approximately 77% crude oil and 80% of which is already operated by us. Offshore leases included in this acquisition total nearly 33,000 net acres.

Outlook

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. Multiple events during 2009 and in 2010 involving numerous financial institutions have effectively restricted 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 remained constrained. We expect that our ability to raise debt and equity will be dependent upon the condition of the capital markets.

Although we currently expect to fund our capital program from existing cash flow from operations, these cash flows are dependent upon future production volumes and commodity prices. Maintaining adequate liquidity may involve the issuance of 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 and pursuing our ultra-deep shelf exploration program.

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.

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 favorable terms, or at all, and we may be unable to refinance our revolving credit facility when it expires. Additionally, should commodity prices decline, our borrowing base under our revolving credit facility may be

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re-determined such that it will not provide for the working capital necessary to fund our capital spending program. The recent explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico, as well as the resulting oil spill, may lead to increased governmental regulation of our and our industry’s operations in a number of areas, including health and safety, environmental, and licensing, any of which could result in significantly increased costs or delays in our current and future drilling operations.

Known Trends and Uncertainties

BP/Deepwater Horizon Oil Spill.  The recent explosion and sinking of the Deepwater Horizon drilling rig and resulting oil spill has created uncertainties about the impact on our future operations in the GOM (see “Item 1A. Risk Factors”). Increased regulation in a number of areas could disrupt, delay or prohibit future drilling programs and ultimately impact the fair value of our unevaluated properties. As of June 30, 2010, we have approximately $85.2 million of investments in unevaluated oil and gas properties that relate to offshore leases. If the fair value of these investments were to fall below the recorded amounts, the excess would be transferred to evaluated oil and gas properties thereby affecting the computation of amounts for depreciation, depletion and amortization and potentially our ceiling test computation. As of June 30, 2010, the computation of our ceiling test indicated a cushion of approximately $780 million.

Hurricanes.  Since the majority of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes is becoming more difficult to obtain. We have narrowed our insurance coverage to selected properties, increased our deductibles and are shouldering more hurricane related risk in the environment of rising insurance rates. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

Results of Operations

Year Ended June 30, 2010 Compared With the Year Ended June 30, 2009.

Our consolidated net income was $27.3 million or $0.56 diluted per common share (“per share”) in fiscal 2010 as compared to a net loss of $571.6 million or $19.77 loss diluted per share in fiscal 2009. The net loss in fiscal 2009 is 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,								Increase (Decrease)				Percent Increase (Decrease)				Revenue Increase (Decrease)
		2010				2009
																		(In Thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)		$	72.48			$	70.62			$	1.86				2.6	%		$	9,955
Natural gas sales prices (per Mcf)			7.15				8.08				(0.93	)			(11.5	)%			(14,446	)
Total price variance																			(4,491	)
Volume Variance
Crude oil sales volumes (MBbls)			5,352				4,146				1,206				29.1	%			85,217
Natural gas sales volumes (MMcf)			15,534				17,472				(1,938	)			(11.1	)%			(15,625	)
BOE sales volumes (MBOE)			7,941				7,058				883				12.5	%
Percent of BOE from crude oil			67.4				58.7
Total volume variance																			69,592
Total price and volume variance																		$	65,101

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Revenue Variances

		Year Ended June 30,								Increase (Decrease)				Percent Increase (Decrease)
		2010				2009
						(In Thousands)
Crude oil		$	387,935			$	292,763			$	95,172				32.5	%
Natural gas			110,996				141,067				(30,071	)			(21.3	)%
Total revenues		$	498,931			$	433,830			$	65,101				15.0	%

Revenues

Our consolidated revenues increased $65.1 million in fiscal 2010. Higher revenues were primarily due to improved crude oil sales volumes and higher crude oil sales prices partially offset the impact of lower natural gas sales volumes and lower natural gas sales prices. Revenue variances related to commodity prices and sales volumes are described below.

Price Variances

Commodity prices are one of our key drivers of earnings generation and net operating cash flow. Lower commodity prices reduced revenues $4.5 million in fiscal 2010. Average natural gas prices, including a $2.68 realized gain per Mcf related to hedging activities, decreased $0.93 per Mcf during fiscal 2010, resulting in decreased revenues of $14.5 million. Average crude oil prices, including an $0.75 realized gain per barrel related to hedging activities, increased $1.86 per barrel in fiscal 2010, resulting in increased revenues of $10.0 million. Commodity prices are affected by many factors that are outside of our control. Commodity prices we received during fiscal 2010 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. Improved BOE sales volumes in fiscal 2010 resulted in increased revenues of $69.6 million. Crude oil sales volumes increased 1,206 MBbls in fiscal 2010, resulting in higher revenues of $85.2 million. The increase in crude oil sales volumes in fiscal 2010 was principally due to the Mit Acquisition coupled with the results of our capital program partially offset by natural decline. Natural gas sales volumes decreased 1,938 MMcf in fiscal 2010, resulting in lower revenues of $15.6 million. The decrease in natural gas sales volumes in fiscal 2010 was primarily due to the effects natural decline.

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.

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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
		2010								2009
		Amount				Per BOE				Amount				Per BOE
		(In Thousands, Except per Unit Amounts)
Costs and expenses
Lease operating expense
Insurance expense		$	27,603			$	3.48			$	19,188			$	2.72			$	8,415
Workover and maintenance			19,630				2.47				15,930				2.26				3,700
Direct lease operating expense			95,379				12.01				87,032				12.33				8,347
Total lease operating expense			142,612				17.96				122,150				17.31				20,462
Production taxes			4,217				0.53				5,450				0.77				(1,233	)
Impairment of oil and gas properties			—				—				576,996				81.75				(576,996	)
DD&A			181,640				22.87				217,207				30.78				(35,567	)
Accretion of asset retirement obligation			23,487				2.96				14,635				2.07				8,852
General and administrative expense			49,667				6.25				24,756				3.51				24,911
Gain on derivative financial instruments			(4,739	)			(0.60	)			(10,147	)			(1.43	)			5,408
Total costs and expenses		$	396,884			$	49.97			$	951,047			$	134.76			$	(554,163	)
Other (income) expense
Interest income		$	(29,756	)		$	(3.75	)		$	(7,498	)		$	(1.06	)		$	(22,258	)
Interest expense			88,239				11.11				84,249				11.93				3,990
Total other (income) expense		$	58,483			$	7.36			$	76,751			$	10.87			$	(18,268	)