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, 2011
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)

Registrant’s telephone number, including area code: (441)-295-2244

 

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 Capital Market

Securities registered pursuant to Section 12(g) of the Act: None

 

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

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 o 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 x		Accelerated filer o
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 $1,771,435,420 based on the closing sale price of $27.67 per share as reported on The NASDAQ Capital Market on December 31, 2010, 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 July 31, 2011 was 76,722,278.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2011 Annual Meeting of Shareholders, which will be filed within 120 days of June 30, 2011, are incorporated by reference into Part III of this Annual Report on Form10-K.

TABLE OF CONTENTS

TABLE OF CONTENTS

		Page
GLOSSARY OF TERMS			ii
PART I
Cautionary Statement Regarding Forward-Looking Statements			1
Item 1 Business			2
Item 1A Risk Factors			12
Item 1B Unresolved Staff Comments			33
Item 2 Properties			33
Item 3 Legal Proceedings			42
Item 4 (Removed and Reserved)			42
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			43
Item 6 Selected Financial Data			44
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations			47
Item 7A Quantitative and Qualitative Disclosures About Market Risk			65
Item 8 Financial Statements and Supplementary Financial Information			68
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			111
Item 9A Controls and Procedures			111
Item 9B Other Information			111
PART III
Item 10 Directors, Executive Officers and Corporate Governance			112
Item 11 Executive Compensation			112
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			112
Item 13 Certain Relationships and Related Transactions, and Director Independence			112
Item 14 Principal Accounting Fees and Services			112
PART IV
Item 15 Exhibits, Financial Statement Schedules			113
Signatures			114

TABLE OF CONTENTS

GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this Annual Report on Form 10-K:

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 installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. For a complete definition of proved developed oil and gas reserves, refer to Rule 4-10(a)(3) of Regulation S-X as promulgated by the Securities and Exchange Commission (“SEC”).

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

Dry Well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

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 and/or stratigraphic condition. For a complete definition of a field, refer to Rule 4-10(a)(8) of Regulation S-X as promulgated by the SEC.

TABLE OF CONTENTS

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

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

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

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

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 BOE based on six 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.

Oil includes crude oil, condensate and natural gas liquids.

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.

Plugging and abandonment refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from a stratum will not escape into another or to the surface. Regulations of many states and the federal government require the plugging of abandoned wells.

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 Rule 4-10(a) (20) of Regulation S-X as promulgated by the SEC.

Productive well is an exploratory, development or extension well that is not a dry well.

Proved area refers to the part of a property to which proved reserves have been specifically attributed.

Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. For a complete definition of proved reserves, refer to Rule 4-10(a)(2) of Regulation S-X as promulgated by the SEC.

Proved undeveloped oil and gas reserves are reserves 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 proved undeveloped oil and gas reserves, refer to Rule 4-10(a)(4) of Regulation S-X as promulgated by the SEC.

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).

Reservoir refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

TABLE OF CONTENTS

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.

Stratigraphic test well refers to a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not drilled in a proved area, or (ii) development-type, if drilled in a proved area.

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.

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K (this “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 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 Form 10-K, (2) our reports and registration statements filed from time to time with the Securities and Exchange Commission (“SEC”) and (3) other public 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 upon which they are made, whether as a result of new information, future events or otherwise.

TABLE OF CONTENTS

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: (1) acquiring producing oil and gas properties; (2) exploiting and exploring our core assets to enhance production and ultimate recovery of reserves; and (3) utilizing a portion of our capital program to explore the ultra-deep shelf for potential oil and gas reserves. As of June 30, 2011, our estimated net proved reserves were 116.6 million BOE, of which 66% 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 Alternative Investment Market of London Stock Exchange (“AIM”). On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, our common stock was admitted for trading on The Nasdaq Global Select Market (“NASDAQ”).

Since our inception in 2005, we have completed five major acquisitions for aggregate cash consideration of approximately $2.5 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 $312.5 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”). On December 17, 2010, we acquired certain shallow-water Gulf of Mexico shelf oil and natural gas interests from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”).

Our core properties at June 30, 2011 were comprised of the following:

TABLE OF CONTENTS

Our average daily production for the year ended June 30, 2011 was 34.6 MBOE per day, of which 68% was oil. Our average daily production for the quarter ended June 30, 2011 was 42.1 MBOE per day, of which approximately 67% was oil. We operate or have an interest in 419 gross producing wells in 41 producing fields. All of our properties are primarily located on the Louisiana Gulf Coast and in the Gulf of Mexico, with approximately 91% of our proved reserves located offshore. We believe this concentration facilitates our ability to manage the operated fields more efficiently, and our high number of wellbore locations provides diversification of our production and reserves. As of June 30, 2011, approximately 83% of our proved reserves were on properties we operate.

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 5,150 square miles, primarily focused on our existing operations. We have identified approximately 190 drilling opportunities on our fields and anticipate drilling 2 – 3 wells in our ultra-deep shelf program that could materially increase our reserve base should it prove successful. Our Board of Directors (“Board”) has approved an initial fiscal 2012 capital budget, excluding any potential acquisitions, but including abandonment costs, of approximately $450 million ($428 million prior to plugging and abandonment costs).

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 Item 7A “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 in the U.S. 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.

TABLE OF CONTENTS

Shell Trading Company (“Shell”) accounted for approximately 61%, 62% and 65% of our total oil and natural gas revenues during the years ended June 30, 2011, 2010 and 2009, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2011. 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 and or ExxonMobil curtailed their 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 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. Our acquisition strategy is to target mature, oil-producing properties in the Gulf of Mexico and the U.S. Gulf Coast that have not been thoroughly depleted by prior operators. We believe these areas will provide us with an inventory of low-risk recompletion and extension opportunities in our geographic area of expertise. Since our inception in 2005, we have completed five major acquisitions, for total consideration of $2.5 billion to acquire 141 MMBOE of net proved reserves. In connection with our acquisitions, we generally enter into hedging arrangements to protect a portion of the acquisition economics.

We regularly engage in discussions with potential sellers regarding acquisition opportunities. These acquisition efforts may involve our participation in auction processes, as well as situations in which we believe we are the only party or one of a limited number of potential buyers in negotiations with the potential seller. These acquisition efforts can involve assets that, if acquired, would have a material effect on our financial condition and results of operations. We finance acquisitions with a combination of funds from our equity offerings, debt offerings, bank borrowings and cash generated from operations.

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 our commodity derivative positions as we increase production to mitigate the impact of commodity price volatility on our business and to help protect our investments.

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, for each target that we believe has potential for significant reserves. Since 2008, we have partnered with McMoRan Exploration Company to explore the ultra-deep shelf. Including the Davy Jones discovery well and Blackbeard West well, the McMoRan-operated partnership (in which we have various interests) has identified approximately 15 ultra-deep shelf prospects in shallow water near existing infrastructure. The Partnership’s short term sub-salt shelf drilling plans include 2 to 3 exploratory wells. We have participated in

TABLE OF CONTENTS

five wells to date with our participations ranging from approximately 16% to 20%. Of these wells, one has been temporarily abandoned pending further evaluation, two are temporarily abandoned pending facilities and completions later this fiscal year and two are currently drilling. We target to spend less than 15% of our cash flow on our exploration activities on the ultra-deep shelf.

Business Strengths

Significant Technical Expertise.  We have assembled a technical staff with an average of over 26 years of industry experience. Our technical staff has specific expertise in developing our core properties. Additionally, members of our senior management team average over 29 years of operating experience in the Gulf of Mexico. We also own an extensive core focused seismic database covering approximately 5,150 square miles, which assists us in identifying attractive development and exploration drilling opportunities.

Oil Focus.  We believe we have a higher percentage of oil in our reserves and production as compared to many of our peers. Given the current commodity price environment and resulting disparity between oil and natural gas prices on a BOE basis, we believe our high percentage of oil reserves compared to our overall reserve base has provided us with an economic advantage. Additionally, the production decline curve of oil is typically lower than a comparable natural gas decline curve, resulting in longer term production on current reserves. Our net proved reserves as of June 30, 2011 were approximately 66% oil.

Operating Control.  As the operator of a property, we are afforded greater control of the optimization of production, the timing and amount of capital expenditures and the operating parameters and costs of our projects. As of June 30, 2011, approximately 83% of our proved reserves are located on properties operated by us.

Geographically Focused Properties in the Gulf of Mexico.  We operate geographically focused producing reserves located in the Gulf of Mexico waters and the U. S. Gulf Coast that give us the opportunity to minimize logistical costs and reduce staffing requirements. Our experience in the Gulf of Mexico has led us to focus our efforts in that particular region, where we are familiar with the fields, drilling and production trends. We believe our asset base is characterized by lower-risk mature properties which have significant well control and predictable production profiles.

Government Regulation

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.  The jurisdictions in which we operate generally require permits for drilling operations, drilling bonds and operating reports 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.

TABLE OF CONTENTS

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.

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 pipeline 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 changing the interstate transportation rates for oil pipelines, 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 (“EPAct 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 EPAct 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. Likewise, the Federal Trade Commission (“FTC”) holds authority to monitor wholesale petroleum markets pursuant to the Federal Trade Commission Act and the Energy Independence and Security Act of 2007. With regard to our physical purchases and sales of natural gas, natural gas liquids, and crude oil, our gathering or transportation 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, FTC 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, order disgorgement of profits, and 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 EPAct 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 EPAct 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 certain information

TABLE OF CONTENTS

daily 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 (3) 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.

Oil Pipeline Regulations.  We own interests in FERC-regulated oil pipelines and have interstate tariffs on file with the FERC setting forth our interstate transportation rates and charges and the rules and regulations applicable to our jurisdictional transportation service. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act (ICA). In October 1992, Congress passed the Energy Policy Act of 1992 (“EPAct of 1992”), which, among other things, required the FERC to issue rules to establish a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by establishing a methodology for petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. Pipelines are allowed to raise their rates to the rate ceiling level generated by application of the index. If the methodology reduces the ceiling level such that it is lower than a pipeline’s filed rate, the pipeline must reduce its rate to conform to the lower ceiling unless doing so would reduce a rate “grandfathered” by EPAct (see below) to below the grandfathered level. A pipeline must, as a general rule, use the indexing methodology to change its rates. Alternatives to the indexing approach that may be used in certain specified circumstances are retained cost-of-service ratemaking, market-based rates, agreement with an unaffiliated shipper, and settlement. The FERC’s indexing methodology is subject to review every five years. On December 16, 2010, the FERC established a new price index — the Producer Price Index for Finished Goods plus 2.65% — for the five-year period beginning July 1, 2011. Requests for rehearing were filed challenging the appropriateness of FERC’s new index. FERC denied rehearing in May 2011 and the new index may be subject to further challenge (for example, on appeal). FERC’s rate-making methodologies limit our ability to set rates that we might otherwise be able to charge, may delay the use of rates that reflect increased costs or reduced volumes and subject us to operational, reporting and other requirements.

Under EPAct of 1992, petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of EPAct of 1992 are deemed to be just and reasonable under the ICA, if such rates had not been subject to complaint, protest or investigation during that 365-day period. Generally, complaints against such “grandfathered” rates may only be pursued if the complainant can show that a substantial change has occurred since the enactment of EPAct of 1992 in either the economic circumstances of the oil pipeline or in the nature of the services provided that were a basis for the rate. EPAct places no such limit on challenges to a provision of an oil pipeline tariff as unduly discriminatory or preferential.

The FERC generally has not investigated rates on its own initiative when those rates have not been the subject of a protest or complaint by a shipper. Shippers may challenge at FERC through protests any proposed, pending interstate oil pipeline rate changes or changes in the rules and regulations governing our transportation service. Shippers may also challenge FERC through complaints regarding effective interstate oil pipeline transportation rates or rules and regulations. Interstate oil pipelines must provide transportation service that is not unduly preferential or unduly discriminatory.

Outer Continental Shelf Pipelines.  The Outer Continental Shelf (“OCS”) Lands Act requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. In June 2008, the Minerals Management Service (now replaced by the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) issued a final rule establishing formal and informal complaint procedures for shippers that believe they have been denied open and nondiscriminatory access to transportation on the OCS. We do not expect the rule to have an impact on our operations or results.

Gathering regulations.  Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own certain natural gas pipelines that we believe meet the traditional tests that 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 FERC, the courts or the U.S. Congress.

TABLE OF CONTENTS

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 differently than other companies in our areas of operation.

Environmental Regulations

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 liabilities for noncompliance and contamination resulting from our operations and may require 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:

Climate Change.  Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

TABLE OF CONTENTS

The U.S. Congress has considered legislation to reduce emissions of greenhouse gases; however, it is uncertain at this time whether, and in what form, such legislation will be adopted in the United States. Both President Obama and the Administrator of the EPA have expressed support for legislation to restrict or regulate emissions of greenhouse gases. In addition, several states, either individually or through multi-state regional initiatives, have already passed laws, adopted regulations or undertaken regulatory activity to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap-and-trade programs. Depending on the particular program, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations, prepare an inventory of greenhouse gas emissions resulting from our operations, or pay a tax on the greenhouse gas emissions resulting from our operations.

Even in the absence of federal legislation, the EPA has begun to regulate greenhouse gas emissions from both mobile and stationary sources. In 2009, the EPA published its finding that greenhouse gases contribute to air pollution that may endanger public health or welfare. Thereafter, the EPA adopted a comprehensive national system for reporting emissions of greenhouse gases for major sources of emissions. On September 22, 2009, the EPA finalized a greenhouse gas reporting rule that requires large sources of greenhouse gas emissions to monitor, maintain records on, and annually report their greenhouse gas emissions. On November 8, 2010, the EPA also issued greenhouse gas monitoring and reporting regulations for petroleum and natural gas facilities, including offshore petroleum and natural gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year that went into effect on December 30, 2010. The rule requires reporting of greenhouse gas emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. In 2010, the EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. The EPA’s greenhouse gas rules are currently undergoing legal challenges and numerous other petitions are pending at the EPA from states and environmental groups seeking additional regulation of a variety of additional sources of greenhouse gas emissions. It is not possible at this time to predict what legislation or new regulations may be adopted to address greenhouse gas emissions or how the adoption of such legislation or regulations would impact our business. However, any new federal, regional or state restrictions on emissions of greenhouse gases imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on our business and the demand for the oil and natural gas we produce.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Due to their location, our operations in the Gulf of Mexico are vulnerable to operational and structural damages resulting from hurricanes and other severe weather systems and our insurance may not cover all associated losses. As discussed below in “Plugging, Abandonment and Decommissioning,” we are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

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

TABLE OF CONTENTS

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.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform in ultra deep water in the Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, the BOEMRE issued a series of “Notices to Lessees” (“NTLs”), and other changes in regulations. In addition, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE,” formerly the Minerals Management Service), of the United States Department of the Interior implemented a six-month moratorium on drilling activities which began in May 2010. There also continue to be many proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and spill. After the moratorium ended in 2010, it was not until March 2011 that a few deep water drilling permits were issued to continue drilling activities that had commenced prior to the Deepwater Horizon incident. The most significant regulation changes in the last twelve months are regulations related to potential environmental impacts, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continues to evolve, we cannot estimate the cost and impact to our business at this time.

We believe our operations are in 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 Regulations

Enterprises that sell securities in public markets are subject to regulatory oversight by agencies such as the SEC. In addition, we are required to comply with the rules of the NASDAQ and the AIM. 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 or AIM 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 186 employees at June 30, 2011. At June 30, 2011, we had no employees represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are good.

TABLE OF CONTENTS

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.

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. Information contained on, or accessible through, our website is not incorporated by reference into this Form 10-K.

TABLE OF CONTENTS

Item 1A. Risk Factors

Risks Related to Our Business

The nature of our business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

We engage in exploration and development drilling activities, which are inherently risky. These 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 U.S. 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 operating risks, which include, but are not limited to:

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:

Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

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 Gulf of Mexico and the U.S. Gulf Coast, our lack of diversification may:

TABLE OF CONTENTS

In addition, the geographic concentration of our properties in the Gulf of Mexico and the U.S. Gulf Coast 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. This damage required us to spend time and capital on inspections, repairs, debris removal, and the drilling of replacement wells. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses. For additional information, please read “— Our insurance may not protect us against business and operating risks.”

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.

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

Our financial condition, revenues, profitability and carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. Commodity 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.

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, 2011 and June 30, 2011 ranged from a high of $113.93 to a low of $84.32 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2011 to June 30, 2011 ranged from a high of $4.85 to a low of $3.78. 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:

TABLE OF CONTENTS

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 downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.

Our actual recovery of reserves may differ from our proved reserve estimates.

This Form 10-K contains estimates of our proved oil and gas 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 in this Form 10-K. 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.

We may be limited in our ability to maintain or book additional proved undeveloped reserves under the SEC’s rules.

We have included in this Form 10-K certain estimates of our proved reserves as of June 30, 2011 prepared in a manner consistent with our and our independent petroleum consultant’s interpretation of the SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies. Included within these 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 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. During the year ended June 30, 2011 we reduced our proved reserve estimates by 3.7 MMBOE due to the five year development rule.

As of June 30, 2011, approximately 30% of our total proved reserves were undeveloped and approximately 19% 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 18% 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.

TABLE OF CONTENTS

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

A large portion of our drilling activity is located in mature oil-producing areas of the U.S. Gulf of Mexico shelf. Accordingly, increases in our future crude oil and natural gas production 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 U.S. 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 U.S. 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 U.S. Gulf of Mexico are depleted within three to four years. Due to high initial production rates, production of reserves from reservoirs in the U.S. Gulf of Mexico generally decline more rapidly than from other producing reservoirs. The vast majority of our existing operations are in the U.S. 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.

Our offshore operations involve special risks that could affect our 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, which may increase costs.

We have participated in five shallow-water ultra-deep shelf wells to date. Of these wells, one has been temporarily abandoned pending further evaluation, two are temporarily abandoned pending facilities and completions later this fiscal year and two are currently drilling. These projects have similar geological characteristics as deepwater prospects with a potential for significant reserves. The shallow water ultra-deep wells are some of the deepest wells ever drilled in the world and are subject to very high pressures and temperatures. The drilling, logging and completion techniques are near the limits of existing technologies. As a result, new technologies and techniques are being developed to deal with these challenges. The use of advanced drilling technologies involves a higher risk of technological failure and potentially higher costs. In addition, there can be delays in completion due to necessary equipment that is specially ordered to handle the challenges of ultra-deep wells.

TABLE OF CONTENTS

Deepwater operations present special risks that may adversely affect the cost and timing of reserve 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 U.S. Gulf of Mexico in the future. Exploration for oil or natural gas in the deepwater of the U.S. 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.

Our insurance may not protect us against all of the operating risks to which our business is exposed.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Due to market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Consistent with industry practice, we are not 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 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 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 U.S. 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 U.S. 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 ours. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from the BOEMRE are acquired through a “sealed

TABLE OF CONTENTS

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. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe will impact attaining success in the industry. 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 reserves.

This Form 10-K contains estimates of our future net cash flows from our proved 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:

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. 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.

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

TABLE OF CONTENTS

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 83% of our proved reserves. 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:

Each of these factors, including others, could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

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

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

TABLE OF CONTENTS

We sell the majority of our production to two customers.

Shell Trading Company (“Shell”) accounted for approximately 61% and ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2011. Our inability to continue to sell our production to Shell and or ExxonMobil, if not offset by sales with new or other existing customers, could have a material adverse effect on our business and operations.

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.

Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.

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.

Our success depends on dedicated and skillful management and staff, whose departure could disrupt our business operations.

Our success depends on our ability to retain and attract experienced engineers, geoscientists and other professional staff. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

TABLE OF CONTENTS

Additionally, if John D. Schiller, Jr. ceases to be our chief executive officer (except as a result of his death or disability) and a reasonably acceptable successor is not appointed, the lenders under EGC’s Second Amended and Restated First Lien Credit Agreement could declare amounts outstanding thereunder immediately due and payable. Such an event could have a material adverse effect on our business and operations.

Risks Related to Our Risk Management Activities

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

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

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

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

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 decrease in 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:

Risks Related to Our Acquisition Strategy

Our acquisitions may be stretching our existing resources.

Since our inception in July 2005, we have made five 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 intensify these risks.

TABLE OF CONTENTS

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 is 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:

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.

TABLE OF CONTENTS

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.

Our business strategy includes a continuing acquisition program, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests. The successful acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:

Our assessment of the acquired properties will not reveal all existing or potential problems nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies. In the course of our due diligence, we historically have not physically inspected every well, platform or pipeline. Even if we had physically inspected each of these, our inspections may not have revealed structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. If an acquired property does not perform as originally estimated, we may have an impairment, which could have a material adverse effect on or financial position and results of operations.

Risks Related to Our Indebtedness and Access to Capital and Financing

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

As of June 30, 2011, we had total indebtedness of $1,113.4 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 financial consequences. For example, they could:

TABLE OF CONTENTS

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 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 our revolving credit facility do not fully prohibit us or our subsidiaries from doing so. At June 30, 2011, we and our subsidiary guarantors collectively had approximately $113.4 million of secured indebtedness and $1.0 billion of other indebtedness. If new debt or liabilities are added to our current debt level, the related risks that we now face could increase.

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

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures and development and exploration efforts will depend on our ability to generate cash in the future. Our future operating performance and financial results will be subject, in part, to factors beyond our control, including interest rates and general economic, financial and business conditions. We cannot assure 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 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 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 was made available to us, it may not be on terms acceptable to us.

TABLE OF CONTENTS

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 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 an 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 may increase substantially while the availability of funds from those markets may diminish 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 may increase as lenders and institutional investors could increase interest rates, impose tighter lending standards, refuse to refinance existing debt at maturity at all or on terms similar to our current debt and, in some cases, cease to provide funding to borrowers.

An increase in our indebtedness, 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 be less favorable 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 may be reduced in the future if commodity prices decline, which will limit our available funding for exploration and development.

As of June 30, 2011, total outstanding borrowings under our revolving credit facility were $107.8 million and our current borrowing base was $750 million. We expect that the next determination of the borrowing base under our revolving credit facility will occur in the fall of 2011. 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 redetermined semi-annually by our lenders at their sole discretion. The lenders will redetermine 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 (1) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (2) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. If oil and natural gas commodity prices deteriorate, 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.

TABLE OF CONTENTS

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.

Any future 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 had an impact on our business and our financial condition, and we may face challenges if economic and financial market conditions deteriorate in the future. 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 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 $750 million.

In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (1) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (2) 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. A return of these conditions could materially and adversely affect our company.

Risks Related to Environmental and Other Regulations

Our operations are 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.

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, FERC has issued various orders that have significantly altered the marketing and transportation

TABLE OF CONTENTS

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. 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 Natural Gas Act (“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:

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.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform in ultra deep water in the Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, the BOEMRE issued a series of “Notices to Lessees” (“NTLs”), and other significant changes in regulations. In addition, the BOEMRE implemented a

TABLE OF CONTENTS

six-month moratorium on drilling activities which began in May 2010. There also continue to be many proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and spill. After the moratorium ended in 2010, it was not until March 2011 that a few deep water drilling permits were issued to continue drilling activities that had commenced prior to the Deepwater Horizon incident. The most significant regulation changes in the last twelve months are regulations related to potential environmental impacts, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continues to evolve, we cannot estimate the cost and impact to our business at this time.

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

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

The Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the Gulf of Mexico, some of which may be unforeseeable.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform in ultra deep water in the Gulf of Mexico. As a result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. Beginning in May 2010, the BOEMRE issued a series of notices to lessees and operators implementing a six-month moratorium on drilling activities in federal offshore waters and imposing a variety of new safety measures and permitting requirements.

In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BOEMRE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico more difficult, more time consuming, and more costly. For example, a variety of amendments to the Oil Pollution Act of 1990 (“OPA”) have been proposed in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the Outer Continental Shelf (the “OCS”), which includes the Gulf of Mexico where we have substantial offshore operations. 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. 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. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. Legislation has been proposed in Congress to amend OPA to increase the minimum level of financial responsibility to $300 million or more. If OPA is amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located on the OCS or enter

TABLE OF CONTENTS

into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased.

New regulatory requirements and permitting procedures recently imposed by the BOEMRE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

Subsequent to the Deepwater Horizon incident in the Gulf of Mexico, the BOEMRE issued a series of NTLs imposing new regulatory requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These new regulatory requirements include the following:

Since the adoption of these new regulatory requirements, BOEMRE has been taking much longer to review and approve permits for new wells. Due to the extremely slow pace of permit review and approval, various industry sources have determined that BOEMRE may take six months or longer to approve applications for drilling permits that were previously approved in less than 30 days. The new rules also increase the cost of preparing each permit application and will increase the cost of each new well, particularly for wells drilled in deeper waters on the OCS.

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

FERC holds 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 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 crude oil and natural gas that we produce.

In December 2009, the U.S. Environmental Protection Agency, or “EPA”, determined 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. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries, on an annual

TABLE OF CONTENTS

basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. 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, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The recent adoption of derivatives legislation by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was signed into law by President Obama on July 21, 2010 and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. 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 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, natural gas liquids and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas liquids 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 adverse effect on us, our financial condition and our results of operations.

TABLE OF CONTENTS

Our company and our 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, which, if required, could be costly and reduce borrowings available under our bank credit facility.

To cover the various obligations of lessees on the U.S. Outer Continental Shelf of the U.S. Gulf of Mexico, the BOEMRE 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 BOEMRE, the BOEMRE 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.

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 cash 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 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. and its subsidiaries, who 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 Fiscal Year 2012 Budget proposed by the President and the recently enacted Budget Control Act of 2011 recommend elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These changes include, but are not limited to, (1) the repeal of the percentage depletion allowance for oil and gas properties; (2) the elimination of current deductions for intangible drilling and development costs; (3) the elimination of the deduction for certain U.S. production activities; and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and the results of operations.

TABLE OF CONTENTS

U.S. persons who own our common shares may have more difficulty in protecting their interests than U.S. persons who are shareholders of a U.S. corporation.

The rights of shareholders under Bermuda law are not as extensive as the rights of shareholders under legislation or judicial precedent in many U.S. jurisdictions. Class actions and derivative actions are generally not available to shareholders under the laws of Bermuda. However, the Bermuda courts ordinarily would be expected to follow English case law precedent, which would permit a shareholder to commence an action in the name of a company to remedy a wrong done to a company where the act complained of is alleged to be beyond the corporate power of a company, is illegal or would result in the violation of our memorandum of association or bye-laws. Furthermore, consideration would be given by the court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of our shareholders than actually approved it. The winning party in such an action generally would be able to recover a portion of attorneys’ fees incurred in connection with such action. Our bye-laws provide that shareholders waive all claims or rights of action that they might have, individually or in the right of the Company, against any director or officer for any act or failure to act in the performance of such director’s or officer’s duties, except with respect to any fraud or dishonesty of such director or officer. Class actions and derivative actions generally are available to stockholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys’ fees incurred in connection with such action.

Our Bye-laws contain provisions that discourage corporate takeovers and could prevent shareholders from realizing a premium on their investment.

Our bye-laws contain provisions that could delay or prevent changes in our management or a change of control that a shareholder might consider favorable. For example, they may prevent a shareholder from receiving the benefit from any premium over the market price of our common shares offered by a bidder in a potential takeover. Even in the absence of a takeover attempt, these provisions may adversely affect the prevailing market price of our common shares if they are viewed as discouraging takeover attempts in the future. For example, provisions in our bye-laws that could delay or prevent a change in management or change in control include:

These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common shares.

The impact of Bermuda’s letter of commitment to the Organisation for Economic Cooperation and Development to eliminate harmful tax practices is uncertain and could affect our tax status in Bermuda.

Bermuda has implemented a legal and regulatory regime that the Organisation for Economic Co-operation and Development (“OECD”) has recognized as generally complying with internationally agreed standards for transparency and exchange of information for tax purposes. This standard has involved Bermuda entering into a number of bilateral tax information exchange agreements which provide that upon request the competent authorities of participating countries shall provide assistance through the exchange of information relevant to the administration or enforcement of domestic laws of the participating countries concerning taxes covered by the agreements without regard to any domestic tax interest requirement or bank secrecy for tax purposes. This includes information that is relevant to the determination, assessment and collection of such

TABLE OF CONTENTS

taxes, the recovery and enforcement of tax claims or the investigation or prosecution of tax matters. Information is to be exchanged in accordance with the agreements and shall be treated as confidential in the manner provided therein. Consequently, shareholders should be aware that in accordance with such arrangements (as extended or varied from time to time to comply with the current international standards, to the extent adopted by Bermuda or any other relevant jurisdiction), relevant information concerning it and/or its investment in the Company may be provided to the competent authority of a jurisdiction with which Bermuda has entered a tax information exchange agreement (or equivalent).

TABLE OF CONTENTS

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Our properties are primarily located in the Gulf of Mexico waters and the U.S. Gulf Coast. Below are descriptions of our significant properties at June 30, 2011 which represent approximately 81% 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 OCS blocks Main Pass 60, 61, 62 and 63. The field was discovered by Pogo in 2000, and has produced in excess of 48 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 23 producing wells and three major production platforms located throughout the field. Since acquiring the field in mid 2007, we have drilled five wells and three sidetracks, performed three rig recompletions, and added acreage via the OCS lease sale. The field’s average net production for the quarter ended June 30, 2011 of 7.6 MBOED, accounted for approximately 18% of our net production for the quarter. Net proved reserves for the field, which is our largest based upon net proved reserves, were 90% oil at June 30, 2011.

West Delta 73.  We operate and have a 100% working interest in the West Delta 73 field, located 28 miles offshore of Grand Isle, Louisiana in approximately 175 feet of water on OCS. The field, which was first discovered in 1962 by Humble Oil and Refining, is a large low relief faulted anticline. The field produces from Pleistocene through Upper Miocene aged sands trapped structurally on the high side closures over the large anticlinal feature from 1,500 feet to 13,000 feet. The field has produced in excess of 315 MMBOE. There are six production platforms and 27 active and 46 shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2011 was 1.8 MBOED. Net proved reserves for the field were 82% oil at June 30, 2011.

West Delta 30.  We operate and have a 75% working interest in the West Delta 30 field, located 21 miles offshore of Grand Isle, Louisiana in approximately 45 feet of water on OCS. The working ownership varies based on unit ownership from 100% to 50% with Maritech being the operator in some wells on the West flank. The field, which was discovered in 1948 by Humble Oil and Refining, is a large salt dome. Pleistocene through Upper Miocene sands are trapped structurally by radial faulting on the flanks of the salt piercement. Productive sands range from 2,000 feet to 17,500 feet in depth and generally produce using moderate water drive. Minor faulting that is secondary to the major normal fault separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 780 MMBOE. There are 12 production platforms and 46 active wells located throughout the field. The field’s average net production for the quarter ended June 30, 2011 was 3.5 MBOED. Net proved reserves for the field were 72% oil at June 30, 2011.

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 was discovered by Gulf Oil in 1977. The field produces from Lower Pliocene sands, which consist of the Discorbis 69 and Discorbis 70 sands, ranging in depths 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 Discorbis 69 and 70 units. The field is produced from one central production platform. The field’s average net production for the quarter ended June 30, 2011 was 2.3 MBOED. Net proved reserves for the field were 58% oil at June 30, 2011.

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 OCS blocks South Timbalier 21, 22, 23, 27 and 28, as well as on two state leases. 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.

TABLE OF CONTENTS

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. There are 10 major production platforms and 61 smaller structures located throughout the field. Since acquiring the field in June 1, 2006, implemented projects include 20 drill wells and 15 rig workovers in this field. The field’s average net production for the quarter ended June 30, 2011 was 3.2 MBOED. Net proved reserves for the field were 75% oil at June 30, 2011.

Bayou Carlin Field.  We currently have a 19% working interest in this field operated by McMoRan located onshore South Louisiana. The discovery well, C.M. Peterson Jr. #1 (Laphroaig) was drilled to 20,250 feet measured depth and put on production in 2007 and has produced 31.2 BCFG and 527 MBC to date. In April 2011, the second well in the field, Laphroaig #2 (Pontiff) was drilled to a total depth of 21,099 feet measured depth and brought on production at a rate of over 50 million cubic feet of natural gas per day, 500 barrels of condensate per day, and zero barrels of water in a newly discovered reservoir. The field’s average net production for the quarter ended June 30, 2011 was 1.0 MBOED. Net proved reserves for the field were 93% gas at June 30, 2011.

South Timbalier 54 Field.  We operate and have a 100% working interest in the South Timbalier 54 field, located 36 miles offshore of Lafourche Parish, Louisiana in approximately 67 feet of water on OCS. The field was originally discovered in 1955 by Humble Oil and Refinery. The field is set up at the confluence of regional and counter/regional fault systems. Pleistocene through Miocene sands are trapped from 4,800’ feet to 17,000’ feet in shallow low relief structures over a deeper seated salt dome and in some combination of structural and stratigraphic traps against salt at depth. Minor faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 132 MMBOE. There are five production platforms and 23 active and 22 shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2011 was 3.7 MBOED. Net proved reserves for the field were 62% oil at June 30, 2011.

Grand Isle 43.  We operate and have a 100% working interest in the West Delta Blocks 72 and 93 of Grand Isle 43 field, located 25 miles offshore of Grand Isle, Louisiana in approximately 150 feet of water on OCS. The field was discovered in 1956 by Conoco and production began on West Delta blocks 72 and 93 in 1964. Located on the west flank of West Delta 73 field, the field produces from Pleistocene through Upper Miocene aged sands on a low relief faulted anticline. Productive sands range from 1,300 feet to 13,000 feet in depth. Some pressure depletion production is found in the deeper Upper Miocene sands. Minor faulting that is secondary to the major normal fault separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 629 MMBOE. There is one production platform and seven active and four shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2011 was 2.1 MBOED. Net proved reserves for the field were 47% oil at June 30, 2011.

Grand Isle 16/18.  We operate and have a 100% working interest in the Grand Isle 16/18 field, located seven miles offshore of Lafourche Parish, Louisiana in approximately 50 feet of water on OCS. The field was originally discovered in 1948 by Humble Oil and Refinery and production begin in 1948. The field consists of two separate shallow piercement salt domes. Pleistocene through Miocene Sands are trapped structurally and stratigraphically from 6,000 feet to 13,000 feet in depth against the salt piercements. Radial faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 515 MMBOE. There are 15 production platforms and 39 active and 45 shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2011 was 2.6 MBOED. Net proved reserves for the field were 84% oil at June 30, 2011.

Main Pass 73 Field.  We have a 100% working interest in and operate the Main Pass 73 field, located in approximately 100 feet of water near the mouth of the Mississippi River and in close proximity to the Main Pass 61 field. This field consists of OCS blocks Main Pass 72, 73, and part of 74. The field was originally discovered in 1976 by Exxon and production began in 1979. 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

TABLE OF CONTENTS

74. Average net production from the complex for the quarter ended June 30, 2011 was 2.3 MBOED. Net proved reserves for the field were 77% oil at June 30, 2011.

In May 12, 2011 we agreed to sell a number of non-core, mostly non-operated, onshore natural gas assets to two private buyers for a total of $39.6 million in cash. The transactions closed on June 27 and June 29, 2011 with an effective date of June 1, 2011. For financial reporting purposes, we recorded revenue and expenses thru the closing date. The assets included about 70 producing wells in 20 fields with recent average net production of 8 million cubic feet per day (MMcf/d) of natural gas and 285 barrels per day (Bbls/d) of oil, or a total equivalent of 1.6 MBOED.

Ultra-Deep Shelf Exploration and Development Activity

We participate in a joint venture (the “Partnership”) led by McMoRan Exploration Company with respect to several prospects in the ultra-deep shelf in the Gulf of Mexico. Data received to date from ultra-deep shelf drilling with respect to the Davy Jones and Blackbeard West discovery wells in the Gulf of Mexico confirm geologic modeling that correlates objective sections on the shelf below the salt weld in the Miocene and older age sections to those productive sections seen in deepwater discoveries by other industry participants. In addition to Davy Jones and Blackbeard West, the Partnership has identified approximately 15 ultra-deep shelf prospects in shallow water near existing infrastructure. The Partnership’s ultra-deep shelf drilling plans in calendar years 2010 and 2011 included the Blackbeard East and Lafitte exploratory wells and delineation drilling at Davy Jones. The Partnership’s near-term sub-salt shelf drilling plans include 2 – 3 exploratory wells. We expect to have sufficient cash flow from operations to fund our current commitments related to our ultra-deep shelf exploration and development activity.

Davy Jones.  In January 2010, the Davy Jones discovery well on South Marsh Island Block 230 (“Davy Jones #1”) was drilled to a total depth of 29,000 feet. As reported in January 2010, the Partnership logged 200 net feet of pay in multiple Eocene/Paleocene (Wilcox) sands in the well. In March 2010, a production liner was set and the well was temporarily abandoned. Facilities construction has already begun while completion equipment has been designed and is being delivered in time for the completion to start in the second half of 2011, that will allow for the flow test to begin in late December with commercial production expected shortly thereafter.

On April 7, 2010, the Partnership commenced drilling the Davy Jones offset appraisal well (“Davy Jones #2”) on South Marsh Island Block 234, two and a half miles southwest of Davy Jones #1. The well has been drilled to a total depth of 30,546 and a 6 5/8” liner was set to TD and the well was suspended awaiting completion. As previously reported, log results above 27,300 feet confirmed 120 net feet of hydrocarbon-bearing Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect. Davy Jones #2 encountered the same Wilcox sand sections that were encountered in the Davy Jones #1, in addition to Tuscaloosa and Cretaceous sections that were encountered deeper in the well. In June 2011, results from wireline logs of the Cretaceous section below 27,300 feet indicated that the Davy Jones No. 2 well encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. The well has been temporarily abandoned pending completion and facilities installation, which is expected to occur in the second half of fiscal 2012.

The Davy Jones play involves a large ultra-deep shelf structure encompassing four lease blocks (20,000 acres). As of June 30, 2011, our investment in both wells at Davy Jones totaled $62 million.

Blackbeard East.  The Blackbeard East ultra-deep shelf exploration well commenced drilling on March 8, 2010 and was drilled to a depth of 32,559 feet. The drill pipe became stuck and upon attempting to retrieve the pipe 1,351 feet of pipe was left in the bottom of the hole. In July 2011, McMoRan commenced operations to drill a by-pass of the well at approximately 30,700 feet to evaluate targets in the Eocene. Based on the drilling data obtained, Energy XXI believes the well encountered the Sparta Sands in the Eocene, which are younger than the Wilcox. Sparta Sands are productive onshore Louisiana. Wireline logs will be required to evaluate this interval. The well, which is located in 80 feet of water on South Timbalier Block 144, has a proposed total depth of 34,000 feet, targeting Middle and Deep Miocene objectives seen below 30,000 feet in Blackbeard West, nine miles away. As of June 30, 2011, our investment in the well totaled $33.7 million.

TABLE OF CONTENTS

Lafitte.  The Lafitte ultra-deep exploration well commenced drilling on October 3, 2010 and is drilling below 25,600 feet and has a proposed total depth of 29,950 feet. Like Blackbeard East, Lafitte will target Middle and Deep Miocene objectives. Lafitte is located on Eugene Island Block 223 in 140 feet of water. As of June 30, 2011, our investment in the well totaled $18.1 million.

Blackbeard West.  Information gained from the Blackbeard East and Lafitte wells will enable the Partnership to consider priorities for future operations at Blackbeard West. As previously reported, the Blackbeard West ultra-deep exploratory well on South Timbalier Block 168 was drilled to 32,997 feet in 2008. Logs indicated four potential hydrocarbon bearing zones that require further evaluation, and the well was temporarily abandoned. The BOEMRE has granted a geophysical Suspension of Operations (“SOO”) to extend the terms of Blackbeard West leases through April 30, 2012 allowing the Partnership to drill an offset location which has been identified. Our investment in the Blackbeard West well totaled $27.1 million at June 30, 2011.

Reserve Estimation Procedures

The information included in this 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 92% of our proved reserves on a valuation basis (the remainder was 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, 2011. The scope and results of NSAI’s procedures are summarized in a letter, which is included as Exhibit 99.1 to this 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 “Item 8. Financial Statements and Supplementary Financial Information.”

The reserve estimates prepared by NSAI are reviewed by members of our senior engineering staff. 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, well test data, historical costs of operation and development or any 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.

The reserve estimates prepared by NSAI along with those reserve estimates prepared by our internal engineering staff are then reviewed by our Vice President of Corporate Development in order to ensure that our reserve estimates are complete and accurate and are in accordance with the rules and regulations of the SEC. Following the review of our Vice President of Corporate Development, NSAI and our senior engineering staff present their respective reserve estimates to our board of directors for review.

However, the preparation of our reserve estimates are in accordance with our prescribed internal control procedures, which include verification of input data into a reserve forecasting and economic evaluation software, as well as management review. The internal controls include but are not limited to the following:

TABLE OF CONTENTS

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:

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, Bobby Poirrier, 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 NSAI. Mr. Poirrier has over 18 years of experience and is a graduate of the Colorado School of Mines with a Bachelor of Science degree in Petroleum Engineering. He is a member of the Society of Petroleum Engineers. Prior to joining Energy XXI in 2010, Mr. Poirrier held engineering positions with Cabot Oil and Gas Corporation and Apache Corporation.

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

Qualifications of Third Party Engineers

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 1997 and has over 30 years of practical experience in petroleum engineering. He graduated with a Bachelor of Science in Petroleum Engineering. NSAI has informed us that he 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 and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines. The technical work was conducted by a team of six NSAI petroleum engineers and geoscientists having an average industry experience of 20 years.

Summary of Oil and Gas Reserves at June 30, 2011

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 (92% 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, 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

TABLE OF CONTENTS

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, 2011 Based on Average Fiscal-Year Prices
		Oil (MBbls)				Natural Gas (MMcf)				MBOE				Percent of Total Proved				PV-10 (in thousands)(1)
Proved
Developed			59,234				134,024				81,572				70	%		$	2,476,871
Undeveloped			17,972				102,292				35,020				30	%			860,605
Total Proved			77,206				236,316				116,592								3,337,476
Future Income taxes																			1,073,278
10% discount																			297,195
Future income taxes discounted at 10%																			776,083
Standardized measure of future discounted net cash flows																		$	2,561,393

Changes in Proved Reserves

Our total proved reserves increased 41.0 MMBOE from 75.6 MMBOE at June 30, 2010 to 116.6 MMBOE at June 30, 2011, primarily attributable to the ExxonMobil Acquisition.

Development of Proved Undeveloped Reserves

Our proved undeveloped reserves at June 30, 2011 were 35.0 MMBOE. Future development costs associated with our proved undeveloped reserves at June 30, 2011 totaled approximately $407 million. In the fiscal year ended June 30, 2011, we developed approximately 4% of our proved undeveloped reserves as of June 30, 2010, consisting of 3 gross, 3 net wells at a net cost of approximately $38.9 million. None of our proved undeveloped well locations remain undeveloped past five years from the date of initial recognition as proved undeveloped. Further, we did not have any proved undeveloped well locations as of June 30, 2011 that were not scheduled to be converted into proved developed reserves within the five year requirement as of June 30, 2011.

TABLE OF CONTENTS

The following table discloses our progress toward the conversion of proved undeveloped reserves during the fiscal year ended June 30, 2011.

		Crude Oil and Natural Gas				Future Development Costs
		(MMBOE)				(In thousands)
Proved undeveloped reserves at June 30, 2010			23.0			$	308,077
Extensions and discoveries			6.1				50,107
Revisions of previous estimates			(1.4	)			(11,500	)
Reclassification of proved undeveloped(1)			(3.7	)			(30,393	)
Acquisition of proved undeveloped reserves			15.0				123,215
Sales of proved undeveloped reserves			(3.4	)			(27,928	)
Conversions to proved developed reserves			(0.6	)			(4,929	)
Total proved undeveloped reserves added			12.0				98,572
Proved undeveloped reserves at June 30, 2011			35.0			$	406,649

Drilling Activity

The following table sets forth our drilling activity.

		Year Ended June 30,
		2011								2010								2009
		Gross				Net				Gross				Net				Gross				Net
Productive wells drilled
Development			10.0				6.0				3.0				1.5				7.0				3.7
Exploratory			4.0				1.0				3.0				0.6				2.0				0.6
Total			14.0				7.0				6.0				2.1				9.0				4.3
Non productive dry wells drilled
Development			1.0				0.3				1.0				1.0				—				—
Exploratory			3.0				1.3				3.0				1.6				6.0				3.5
Total			4.0				1.6				4.0				2.6				6.0				3.5

Present Activities

As of June 30, 2011, five gross wells, representing approximately 1.9 net wells, were being drilled which include the ultra-deep shelf well Lafitte and the well on South Timbalier 144, also known as Blackbeard East.

Delivery Commitments

As of June 30, 2011, we had no delivery commitments.

Productive Wells

Our working interests in productive wells follow.

		June 30,
		2011								2010
		Gross				Net				Gross				Net
Natural Gas			88				56				118				39
Crude Oil			331				257				169				106
Total			419				313				287				145

TABLE OF CONTENTS

Acreage

Working interests in developed and undeveloped acreage follow.

		June 30, 2011
		Developed Acres								Undeveloped Acres								Total Acres
		Gross				Net				Gross				Net				Gross				Net
Onshore			41,463				19,687				5,317				2,683				46,780				22,370
Offshore			409,225				235,204				166,462				66,639				575,687				301,843
Total			450,688				254,891				171,779				69,322				622,467				324,213

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

		Year Ending June 30,
		2012								2013								2014
		Gross				Net				Gross				Net				Gross				Net
Onshore			1,006				828				1,728				1,728				764				764
Offshore			—				—				52,165				51,944				25,754				25,754
Total			1,006				828				53,893				53,672				26,518				26,518

Capital Expenditures, Including Acquisitions and Costs Incurred

Property acquisition costs:

		Year Ended June 30,
		2011				2010				2009
		(In Thousands)
Oil and Gas Activities
Development		$	180,191			$	92,949			$	142,848
Exploration			98,133				51,030				121,554
Acquisitions			1,012,262				293,037				—
Administrative and other			2,909				1,133				1,610
Capital expenditures, including acquisitions			1,293,495				438,149				266,012
Asset retirement obligations, insurance proceeds and other, net			205,702				17,996				71,788
Total costs incurred		$	1,499,197			$	456,145			$	337,800

TABLE OF CONTENTS

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,
		2011				2010				2009
Sales Volumes per Day
Natural gas (MMcf)			67.2				42.6				47.9
Crude oil (MBbls)			23.4				14.7				11.4
Total (MBOE)			34.6				21.8				19.3
Percent of BOE from crude oil			68	%			67	%			59	%
Average Sales Price
Natural gas per Mcf		$	4.15			$	4.47			$	6.48
Hedge gain per Mcf			1.54				2.68				1.60
Total natural gas per Mcf		$	5.69			$	7.15			$	8.08
Crude oil per Bbl		$	90.95			$	71.73			$	67.06
Hedge gain (loss) per Bbl			(6.80	)			0.75				3.56
Total crude oil per Bbl		$	84.15			$	72.48			$	70.62
Sales price per BOE		$	69.59			$	57.09			$	55.43
Hedge gain (loss) per BOE			(1.61	)			5.74				6.04
Total sales price per BOE		$	67.98			$	62.83			$	61.47

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

The following field contains 15% or more of our total proved reserves as of June 30, 2011. Our average daily production, average sales prices and production cost follow.

		Year Ended June 30,
		2011				2010				2009
Main Pass 61
Sales Volumes per Day
Natural gas (MMcf)			3.0				3.5				2.7
Crude oil (MBbls)			7.2				5.8				3.6
Total (MBOE)			7.7				6.4				4.1
Percent of BOE from crude oil			94	%			91	%			88	%
Average Sales Price
Natural gas per Mcf		$	4.44			$	4.99			$	6.71
Crude oil per Bbl		$	88.62			$	75.37			$	64.31
Production Cost per BOE		$	10.30			$	11.37			$	7.82

TABLE OF CONTENTS

Production Unit Costs

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

		Year Ended June 30,
		2011				2010				2009
Average Costs per BOE
Production costs
Lease operating expense
Insurance expense		$	2.33			$	3.48			$	2.72
Workover and maintenance			2.90				2.47				2.26
Direct lease operating expense			14.70				12.01				12.33
Total lease operating expense			19.93				17.96				17.31
Production taxes			0.26				0.53				0.77
Total production costs		$	20.19			$	18.49			$	18.08
Depreciation, depletion and amortization rates		$	23.22			$	22.87			$	30.78

Sale of Certain Onshore Properties

In 2011, we closed on the sales of certain onshore crude oil and natural gas properties for cash consideration of $39.6 million. The properties included about 70 producing wells in 20 fields with current net production of 8 MMcf/d of natural gas and 285 Bbl/d of crude oil, or a total equivalent of 1.6 BOE/d.

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 adverse effect on our financial position or results of operations.

Item 4. (Removed and Reserved)

TABLE OF CONTENTS

PART II

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

Market Information for Common Stock

On August 1, 2007, our unrestricted common stock was admitted for trading on The NASDAQ Capital Market under the symbol “EXXI.” On August 12, 2011, our common stock was admitted for trading on The Nasdaq Global Select Market (“NASDAQ”) and continues to trade 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 unrestricted common stock as reported on the NASDAQ.

		Unrestricted Common Stock
		High				Low
Fiscal 2010
First Quarter		$	9.45			$	2.25
Second Quarter			12.35				7.10
Third Quarter			20.85				12.35
Fourth Quarter			22.38				13.48
Fiscal 2011
First Quarter			23.45				15.05
Second Quarter			28.25				21.55
Third Quarter			34.48				26.62
Fourth Quarter			36.52				29.08

As of July 31, 2011, there were approximately 335 holders of record of our unrestricted common stock.

Dividend Information

On September 9, 2008, our 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, our 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, our Board declared a cash dividend of $0.025 per common share, payable on March 13, 2009 to shareholders of record on February 20, 2009.

Purchases of Equity Securities

During the year ended June 30, 2011, we did not purchase any of our equity securities.

TABLE OF CONTENTS

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 Form 10-K.

		Year Ended June 30,
		2011				2010				2009				2008				2007
		(In Thousands, Except per Share Amounts)
Income Statement Data
Revenues		$	859,370			$	498,931			$	433,830			$	643,232			$	341,284
Depreciation, Depletion and Amortization (“DD&A”)			293,479				181,640				217,207				307,389				145,928
Impairment of Oil and Gas Properties			—				—				576,996				—				—
Operating Income (Loss)			208,923				102,047				(517,217	)			143,600				95,215
Other Income (Expense) – Net			(132,006	)			(58,483	)			(76,751	)			(101,857	)			(58,420	)
Net Income (Loss)			64,655				27,320				(571,629	)			26,869				24,130
Basic Earnings (Loss) per Common Share		$	0.42			$	0.56			$	(19.77	)		$	1.57			$	1.45
Diluted Earnings (Loss) per Common Share		$	0.42			$	0.56			$	(19.77	)		$	1.49			$	1.45
Cash Flows Data
Provided by (Used in)
Operating Activities		$	387,725			$	121,213			$	245,835			$	414,647			$	270,783
Investing Activities
Acquisitions			(1,012,262	)			(293,037	)			—				(40,016	)			(717,618	)
Investment in properties			(281,233	)			(145,112	)			(266,012	)			(357,173	)			(427,213	)
Other			38,423				53,989				2,935				(296	)			1,955
Total Investing Activities			(1,255,072	)			(384,160	)			(263,077	)			(397,485	)			(1,142,876	)
Financing Activities			881,530				188,246				(62,795	)			132,016				829,488
Increase (Decrease) in Cash		$	14,183			$	(74,701	)		$	(80,037	)		$	149,178			$	(42,605	)
Dividends Paid per Average Common Share			—				—			$	0.075				—				—

		June 30,
		2011				2010				2009				2008				2007
		(In Thousands)
Balance Sheet Data
Total Assets		$	2,798,860			$	1,566,491			$	1,328,662			$	2,049,931			$	1,648,442
Long-term Debt Including Current Maturities			1,113,387				774,600				862,827				952,222				1,051,019
Stockholders’ Equity			946,697				436,561				127,500				374,585				397,126
Common Shares Outstanding			76,204				50,637				29,150				28,987				16,840

TABLE OF CONTENTS

		Year Ended June 30,
Operating Highlights		2011				2010				2009				2008				2007
		(In Thousands, Except per Unit Amounts)
Operating revenues
Crude oil sales		$	777,869			$	383,928			$	278,014			$	484,552			$	177,783
Natural gas sales			101,815				69,399				113,156				237,628				131,065
Hedge gain (loss)			(20,314	)			45,604				42,660				(78,948	)			32,436
Total revenues			859,370				498,931				433,830				643,232				341,284
Percent of operating revenues from crude oil
Prior to hedge gain (loss)			88	%			85	%			71	%			67	%			58	%
Including hedge gain (loss)			84	%			78	%			68	%			62	%			57	%
Operating expenses
Lease operating expense
Insurance expense			29,468				27,603				19,188				18,218				12,670
Workover and maintenance			36,619				19,630				15,930				22,397				8,269
Direct lease operating expense			185,890				95,379				87,032				102,244				48,046
Total lease operating expense			251,977				142,612				122,150				142,859				68,985
Production taxes			3,336				4,217				5,450				8,686				3,595
Depreciation, depletion and amortization			293,479				181,640				217,207				307,389				145,928
Impairment of oil and gas properties			—				—				576,996				—				—
General and administrative			75,091				49,667				24,756				26,450				26,507
Other – net			26,564				18,748				4,488				14,248				1,054
Total operating expenses			650,447				396,884				951,047				499,632				246,069
Operating income (loss)		$	208,923			$	102,047			$	(517,217	)		$	143,600			$	95,215
Sales volumes per day
Natural gas (MMcf)			67.2				42.6				47.9				75.7				50.3
Crude oil (MBbls)			23.4				14.7				11.4				13.5				7.8
Total (MBOE)			34.6				21.8				19.3				26.2				16.2
Percent of sales volumes from crude oil			68	%			67	%			59	%			52	%			48	%
Average sales price
Natural gas per Mcf		$	4.15			$	4.47			$	6.48			$	8.57			$	7.13
Hedge gain per Mcf			1.54				2.68				1.60				0.34				0.90
Total natural gas per Mcf		$	5.69			$	7.15			$	8.08			$	8.91			$	8.03
Crude oil per Bbl		$	90.95			$	71.73			$	67.06			$	97.72			$	62.33
Hedge gain (loss) per Bbl			(6.80	)			0.75				3.56				(17.82	)			5.60
Total crude oil per Bbl		$	84.15			$	72.48			$	70.62			$	79.90			$	67.93
Total hedge gain (loss) per BOE		$	(1.61	)		$	5.74			$	6.04			$	(8.24	)		$	5.48
Operating revenues per BOE		$	67.98			$	62.83			$	61.47			$	67.16			$	57.71
Operating expenses per BOE
Lease operating expense
Insurance expense			2.33				3.48				2.72				1.90				2.14
Workover and maintenance			2.90				2.47				2.26				2.34				1.40
Direct lease operating expense			14.70				12.01				12.33				10.68				8.12
Total lease operating expense			19.93				17.96				17.31				14.92				11.66
Production taxes			0.26				0.53				0.77				0.91				0.61
Impairment of oil and gas properties			—				—				81.75				—				—
Depreciation, depletion and amortization			23.22				22.87				30.78				32.09				24.68
General and administrative			5.94				6.25				3.51				2.76				4.48
Other – net			2.10				2.36				0.64				1.49				0.18
Total operating expenses			51.45				49.97				134.76				52.17				41.61
Operating income (loss) per BOE		$	16.53			$	12.86			$	(73.29	)		$	14.99			$	16.10

TABLE OF CONTENTS

		Quarter Ended
Operating Highlights		June 30, 2011				Mar. 31, 2011				Dec. 31, 2010				Sept. 30, 2010				June 30, 2010
		(In Thousands, Except per Unit Amounts)
Operating revenues
Crude oil sales		$	270,252			$	233,081			$	156,273			$	118,263			$	113,908
Natural gas sales			31,875				32,193				18,301				19,446				19,945
Hedge gain (loss)			(19,346	)			(6,638	)			(621	)			6,291				5,538
Total revenues			282,781				258,636				173,953				144,000				139,391
Percent of operating revenues from crude oil
Prior to hedge gain (loss)			89	%			88	%			90	%			86	%			85	%
Including hedge gain (loss)			85	%			84	%			84	%			80	%			79	%
Operating expenses
Lease operating expense
Insurance expense			9,549				7,278				6,498				6,143				7,220
Workover and maintenance			20,579				4,317				4,105				7,618				5,269
Direct lease operating expense			62,362				58,471				34,644				30,413				28,816
Total lease operating expense			92,490				70,066				45,247				44,174				41,305
Production taxes			1,205				721				716				694				1,065
DD&A			85,179				91,301				62,922				54,077				50,556
General and administrative			17,553				23,155				15,786				18,597				13,127
Other – net			7,730				9,288				4,710				4,836				5,116
Total operating expenses			204,157				194,531				129,381				122,378				111,169
Operating income		$	78,624			$	64,105			$	44,572			$	21,622			$	28,222
Sales volumes per day
Natural gas (MMcf)			83.0				84.6				53.7				48.1				48.2
Crude oil (MBbls)			28.3				27.3				20.4				17.9				17.3
Total (MBOE)			42.1				41.4				29.4				25.9				25.3
Percent of sales volumes from crude oil			67	%			66	%			70	%			69	%			68	%
Average sales price
Natural gas per Mcf		$	4.22			$	4.23			$	3.70			$	4.39			$	4.55
Hedge gain per Mcf			1.37				1.28				1.85				1.97				2.27
Total natural gas per Mcf		$	5.59			$	5.51			$	5.55			$	6.36			$	6.82
Crude oil per Bbl		$	105.12			$	94.94			$	83.14			$	71.79			$	72.42
Hedge loss per Bbl			(11.53	)			(6.67	)			(5.18	)			(1.48	)			(2.80	)
Total crude oil per Bbl		$	93.59			$	88.27			$	77.96			$	70.31			$	69.62
Total hedge gain (loss) per BOE		$	(5.05	)		$	(1.78	)		$	(0.23	)		$	2.64			$	2.40
Operating revenues per BOE		$	73.85			$	69.46			$	64.34			$	60.37			$	60.50
Operating expenses per BOE
Lease operating expense
Insurance expense			2.49				1.95				2.40				2.58				3.13
Workover and maintenance			5.37				1.16				1.52				3.19				2.29
Direct lease operating expense			16.29				15.70				12.81				12.75				12.51
Total lease operating expense			24.15				18.81				16.73				18.52				17.93
Production taxes			0.31				0.19				0.26				0.29				0.46
DD&A			22.24				24.52				23.27				22.67				21.94
General and administrative			4.58				6.22				5.84				7.80				5.70
Other – net			2.01				2.49				1.74				2.02				2.22
Total operating expenses			53.29				52.23				47.84				51.30				48.25
Operating income per BOE		$	20.56			$	17.23			$	16.50			$	9.07			$	12.25

TABLE OF CONTENTS

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 Form 10-K. 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: (1) acquiring producing oil and gas properties; (2) exploiting and exploring our core assets to enhance production and ultimate recovery of reserves; and (3) utilizing a portion of our capital program to explore the ultra-deep shelf for potential oil and gas reserves.

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, 2011, excluding acquisitions, approximately 64% of our capital expenditures were associated with the exploitation of existing properties.

At June 30, 2011, our total proved reserves were 116.6 MMBOE of which 66% were oil and 70% were classified as proved developed. We operated or had an interest in 419 gross producing wells on 254,891 net developed acres, including interests in 41 producing fields. All of our properties are primarily located on the U.S. Gulf Coast and in the Gulf of Mexico, with approximately 91% 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, and approximately 83% of our proved reserves are on properties operated by us. We have a seismic database covering approximately 5,150 square miles, primarily focused on our existing operations. This database has helped us identify approximately 190 drilling opportunities. We believe the mature legacy fields on our acquired properties will lend themselves well to our aggressive exploitation strategy, and we expect to identify incremental exploration opportunities on the properties.

We are actively engaged in a program designed to manage our commodity price risk and we seek to hedge the majority of our proved developed producing reserves to enhance cash flow certainty and predictability. In connection with our acquisitions, we typically enter into hedging arrangements to minimize commodity downside exposure. We believe our disciplined risk management strategy provides substantial price protection, as our cash flow on the hedged portion is driven by production results rather than commodity prices. We believe this greater price certainty allows us to more efficiently manage our cash flows and allocate our capital resources.

Acquisitions

Marlin.  On February 21, 2006, we entered into a definitive agreement with Marlin to acquire 100% of the membership interests in Marlin and Marlin Texas GP, L.L.C. and the limited partnership interests in Marlin Texas, L.P. for total cash consideration of approximately $448.4 million.

Castex.  On June 7, 2006, we entered into a definitive agreement with affiliates of Castex to acquire certain oil and natural gas properties in Louisiana. We closed the Castex Acquisition on July 28, 2006. Our cash cost of the acquisition was approximately $312.5 million.

Pogo Properties.  On June 8, 2007, we purchased the Pogo Properties from Pogo for approximately $415.1 million.

TABLE OF CONTENTS

Mit Acquisition.  On December 22, 2009, we closed on the acquisition of certain Gulf of Mexico shelf oil and natural gas interests from MitEnergy for cash consideration of $276.2 million. The Mit Acquisition involved mirror-image non-operated interests in the same group of properties we purchased from Pogo in June 2007. These properties included 30 fields of which production was approximately 77% crude oil and 80% of which was already operated by us. Offshore leases included in this acquisition totaled nearly 33,000 net acres.

ExxonMobil Acquisition.  On December 17, 2010, we closed on the purchase of certain shallow-water Gulf of Mexico shelf oil and natural gas interests from ExxonMobil for $1.01 billion in cash, subject to adjustment. The properties involved in the ExxonMobil Acquisition had estimated proved reserves as of November 30, 2010 of 49.5 MMBOE of which 61% were oil and 68% were proved developed; were located in water depths of 470 feet or less; included 160 producing wells in nine fields and included approximately 393 miles of gathering lines as well as seismic data and field studies related to the properties.

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, 2010 and 2011 involving numerous financial institutions and the market, in general, impacted liquidity within the capital markets throughout the United States and around the world during these periods. Despite efforts by the U.S. Treasury Department and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector, capital markets remain constrained. As a result, we expect that our ability to raise debt and equity and the terms on which we can raise capital 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 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 2013 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 also are subject to natural gas and oil production declines. We attempt to replace this declining production through our drilling and recompletion program and acquisitions. 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. Consistent 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 additional debt and equity on acceptable 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 reduced thereby eliminating the working capital necessary to fund our capital spending program as well as potentially requiring us to repay certain of our outstanding indebtedness. The explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico, as well as the resulting oil spill, have also led to increased governmental regulation of

TABLE OF CONTENTS

our and our industry’s operations in a number of areas, including health and safety, environmental, and licensing, any of which could result in increased costs or delays in our current and future drilling operations.

Known Trends and Uncertainties

Deepwater Horizon Oil Spill.  The 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 Gulf of Mexico (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, 2011, we have approximately $142.7 million of investments in unevaluated oil and gas properties related to the ultra-deep shelf exploration. 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, 2011, the computation of our ceiling test indicated a cushion of approximately $950 million.

Hurricanes.  Since the majority of our production originates in the Gulf of Mexico, 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. 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.

Ultra-Deep Shelf Exploration and Development.  We participate in a joint venture (the “Partnership”) led by McMoRan Exploration Company with respect to several prospects in the ultra-deep shelf in the Gulf of Mexico. Data received to date from ultra-deep shelf drilling with respect to the Davy Jones and Blackbeard West discovery wells in the Gulf of Mexico confirm geologic modeling that correlates objective sections on the shelf below the salt weld in the Miocene and older age sections to those productive sections seen in deepwater discoveries by other industry participants. In addition to Davy Jones and Blackbeard West, the Partnership has identified approximately 15 ultra-deep shelf prospects in shallow water near existing infrastructure. We expect to have sufficient cash flow from operations to fund our current commitments related to our ultra-deep shelf exploration and development activity. We have participated in five wells to date with our participations ranging from approximately 16% to 20%. Of these wells, one is pending further evaluation and four are in process. We target to spend less than 15% of our cash flow on our exploration activities on the ultra-deep shelf. Of the five wells with activity to date, one has been temporarily abandoned pending further evaluation, two are temporarily abandoned pending facilities and completions later this fiscal year and two are currently drilling. Based on the results of these wells, our proved reserves may vary from our current 66% oil composition.

Results of Operations

The data presented below excludes results from the (1) ExxonMobil Acquisition for periods prior to the closing dates in December 2010 and (2) MitEnergy Acquisition for periods prior to November 2009.

Year Ended June 30, 2011 Compared With the Year Ended June 30, 2010

Our consolidated income available for common stockholders was $27.7 million or $0.42 diluted per common share (“per share”) in fiscal 2011 as compared consolidated income available for common stockholders of $23.0 million or $0.56 diluted income per share in fiscal 2010. Below is a discussion of prices, volumes and revenue variances.

TABLE OF CONTENTS

Sales Price and Volume Variances

		Year Ended June 30,								Increase (Decrease)				Percent Increase (Decrease)				Revenue Increase (Decrease)
		2011				2010
																		(In Thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)		$	84.15			$	72.48			$	11.67				16	%		$	99,814
Natural gas sales prices (per Mcf)			5.69				7.15				(1.46	)			(20	)%			(35,818	)
Total price variance																			63,996
Volume Variance
Crude oil sales volumes (MBbls)			8,553				5,352				3,201				60	%			231,934
Natural gas sales volumes (MMcf)			24,533				15,534				8,999				58	%			64,509
BOE sales volumes (MBOE)			12,642				7,941				4,701				59	%
Percent of BOE from crude oil			68				67
Total volume variance																			296,443
Total price and volume variance																		$	360,439

Revenue Variances

		Year Ended June 30,								Increase (Decrease)				Percent Increase (Decrease)
		2011				2010
						(In Thousands)
Crude oil		$	719,683			$	387,935			$	331,748				86	%
Natural gas			139,687				110,996				28,691				26	%
Total revenues		$	859,370			$	498,931			$	360,439				72	%

Oil and Natural Gas Revenues

Our consolidated revenues increased $360.4 million in fiscal 2011. Higher revenues were primarily due to improved crude oil and natural gas sales volumes and higher crude oil sales prices partially offset by the impact of lower natural gas sales prices. Revenue variances related to commodity prices and sales volumes are described below.

Sales Price Variances

Commodity prices are one of our key drivers of earnings generation and net operating cash flow. Higher net commodity prices increased revenues by $64.0 million in fiscal 2011. Average natural gas prices, including a $1.54 realized gain per Mcf related to hedging activities, decreased $1.46 per Mcf during fiscal 2011, resulting in decreased revenues of $35.8 million. Average crude oil prices, including a $6.80 realized loss per barrel related to hedging activities, increased $11.67 per barrel in fiscal 2011, resulting in increased revenues of $99.8 million. Commodity prices are affected by many factors that are outside of our control. Commodity prices we received during fiscal 2011 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.

Sales Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Improved BOE sales volumes in fiscal 2011 resulted in increased revenues of $296.4 million. Crude oil sales volumes increased 3,201 MBbls in fiscal 2011, resulting in higher revenues of $231.9 million. The increase in crude oil sales volumes in fiscal 2011 was principally due to the ExxonMobil Acquisition coupled with the results of our capital program partially offset by natural decline. Natural gas sales volumes increased 8,999 MMcf in

TABLE OF CONTENTS

fiscal 2011, resulting in improved revenues of $64.5 million. The increase in natural gas sales volumes in fiscal 2011 was primarily due to the ExxonMobil Acquisition coupled with the results of our capital program partially offset by 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.

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
		2011								2010
		Amount				Per BOE				Amount				Per BOE
		(In Thousands, except per unit amounts)
Costs and expenses
Lease operating expense
Insurance expense		$	29,468			$	2.33			$	27,603			$	3.48			$	1,865
Workover and maintenance			36,619				2.90				19,630				2.47				16,989
Direct lease operating expense			185,890				14.70				95,379				12.01				90,511
Total lease operating expense			251,977				19.93				142,612				17.96				109,365
Production taxes			3,336				0.26				4,217				0.53				(881	)
DD&A			293,479				23.22				181,640				22.87				111,839
Accretion of asset retirement obligation			32,127				2.54				23,487				2.96				8,640
General and administrative expense			75,091				5.94				49,667				6.25				25,424
Gain on derivative financial instruments			(5,563	)			(0.44	)			(4,739	)			(0.60	)			(824	)
Total costs and expenses		$	650,447			$	51.45			$	396,884			$	49.97			$	253,563
Other (income) expense
Other (income) expense – other		$	26,157			$	2.07			$	(29,756	)		$	(3.75	)		$	55,913
Interest expense			105,849				8.37				88,239				11.11				17,610
Total other (income) expense		$	132,006			$	10.44			$	58,483			$	7.36			$	73,523

Costs and expenses increased $253.6 million in fiscal 2011. This increase in costs and expenses was due in part to the ExxonMobil Acquisition which increased production related expenses in fiscal 2011 coupled with higher general and administrative expense. Below is a discussion of costs and expenses.

Lease operating expense increased $109.4 million in fiscal 2011 compared to fiscal 2010. This increase was primarily due to higher direct lease operating and workover and maintenance expenses stemming from the increase in producing properties resulting from the ExxonMobil Acquisition and from our capital program.

DD&A expense increased $111.8 million primarily due to a higher DD&A rate ($4.4 million) as result of the ExxonMobil Acquisition and the higher cost to add reserves coupled with the impact of higher equivalent production ($107.4) million.

Accretion of asset retirement obligations increased $8.6 million primarily as a result of the increase in additional asset retirement obligations acquired during fiscal 2011.

The increase in gain on derivative financial instruments in fiscal 2011 compared to fiscal 2010 of $0.8 million is principally due to the turnaround related to the net price ineffectiveness of our hedged crude oil and natural gas contracts.

Production taxes decreased $0.9 million primarily as a result of lower Texas onshore production.

TABLE OF CONTENTS

General and administrative expense increased $25.4 million in fiscal 2011 principally as a result of higher compensation expense related to Phantom and Performance Units due to our rising common stock price.

Other (income) expense increased $73.5 million in fiscal 2011 as compared to fiscal 2010. This increase was primarily due to the items discussed below.

Other (income) expense – other increased $55.9 million principally due to the loss on redemption of the Second Lien Notes and the Bridge Loan commitments of $26.4 million in fiscal 2011 as compared to a gain of $26.7 million related to the repurchased $126.0 million of New Notes in fiscal 2010. Interest expense increased $17.6 million due to an increase in borrowing partially offset by a decrease in interest rates. On a per unit of production basis, interest expense decreased 25%, from $11.11/BOE to $8.37/BOE.

Income Tax Expense

Income tax expense decreased $4.0 million in fiscal 2011 compared to fiscal 2010, primarily due to the partial release of the valuation allowance which offset the tax expense on U.S. operations’ income. A significant portion of income tax expense consists of U.S. withholding taxes provided on outbound intercompany interest accrued during the year. The effective income tax rate for fiscal 2011 decreased from fiscal 2010 from 37% to 16%.

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.

Sales 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				3	%		$	9,955
Natural gas sales prices (per Mcf)			7.15				8.08				(0.93	)			(12	)%			(14,446	)
Total price variance																			(4,491	)
Volume Variance
Crude oil sales volumes (MBbls)			5,352				4,146				1,206				29	%			85,217
Natural gas sales volumes (MMcf)			15,534				17,472				(1,938	)			(11	)%			(15,625	)
BOE sales volumes (MBOE)			7,941				7,058				883				13	%
Percent of BOE from crude oil			67				59
Total volume variance																			69,592
Total price and volume variance																		$	65,101

Revenue Variances

		Year Ended June 30,								Increase (Decrease)				Percent Increase (Decrease)
		2010				2009
						(In Thousands)
Crude oil		$	387,935			$	292,763			$	95,172				33	%
Natural gas			110,996				141,067				(30,071	)			(21	)%
Total revenues		$	498,931			$	433,830			$	65,101				15	%