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, 2012
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 Stock 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 x No o

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

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

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

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 $1,704,223,329 based on the closing sale price of $31.88 per share as reported on The NASDAQ Global Select Market on December 30, 2011, 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, 2012 was 79,275,890.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2012 Annual Meeting of Shareholders, which will be filed within 120 days of June 30, 2012, are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS		ii
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		1
PART I
Item 1 Business		2
Item 1A Risk Factors		18
Item 1B Unresolved Staff Comments		36
Item 2 Properties		36
Item 3 Legal Proceedings		36
Item 4 Mine Safety Disclosures		36
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		37
Item 6 Selected Financial Data		38
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations		41
Item 7A Quantitative and Qualitative Disclosures About Market Risk		59
Item 8 Financial Statements and Supplementary Data		62
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		105
Item 9A Controls and Procedures		105
Item 9B Other Information		105
PART III
Item 10 Directors, Executive Officers and Corporate Governance		106
Item 11 Executive Compensation		106
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		106
Item 13 Certain Relationships and Related Transactions, and Director Independence		106
Item 14 Principal Accounting Fees and Services		106
PART IV
Item 15 Exhibits, Financial Statement Schedules		107
Signatures		108

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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. Natural gas is converted into one BOE based on six Mcf of gas to one barrel of oil	MBOE	One thousand BOEs
DD&A	Depreciation, Depletion and Amortization	MMBOE	One million BOEs

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

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

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

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.

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.

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Gathering and transportation is the cost of moving crude oil from several wells into a single tank battery or major pipeline.

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.

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

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

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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.

iv

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 significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause actual results to differ materially from those in the forward-looking statements include 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 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.

1

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 trend for potential oil and gas reserves. As of June 30, 2012, our estimated net proved reserves were 119.6 million BOE, of which 71% was oil and 68% was proved developed. Of the oil, 94% was crude oil and condensate with natural gas liquids comprising the remaining 6%. We are the third largest oil producer on the Gulf of Mexico Shelf with interest in six of the eleven largest oil fields in the Gulf of Mexico Shelf.

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 the 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 for approximately $415.1 million (the “Pogo Acquisition”). 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”).

Business Strategy

Acquire Producing Assets.  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.

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. 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 Trend.  Using a portion of our exploration budget, we explore for ultra-deep reserves on the shelf (depths in excess of 20,000 feet and water depths of less than 150 feet) and onshore (depths in excess of 20,000 feet) of the Gulf of Mexico, for each target that we believe has potential for significant reserves. Ultra-deep is considered a well that drills below the salt/saltweld. Since 2008, we have partnered with McMoRan Exploration Company to explore the ultra-deep trend. Including the Davy Jones

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discovery well, Davy Jones Offset, Blackbeard East, Lafitte and Blackbeard West wells, the McMoRan-operated group (in which we have various interests) has identified approximately 15 ultra-deep prospects in shallow water near existing infrastructure. In addition we will participate in three onshore ultra-deep prospects located in South Louisiana. The group’s current sub-salt drilling plans include 2 to 3 exploratory wells. We have participated in 7 wells to date with our participations ranging from approximately 9% to 20%. Of these wells, one has been temporarily abandoned pending further evaluation, three are temporarily abandoned pending facilities and completions, two are currently drilling and one is currently being tested. We target to spend less than 10% of our budgeted cash flow on our exploration activities on the ultra-deep trend.

Business Strengths

Significant Technical Expertise.  We have assembled a technical staff with an average of over 23 years of industry experience. Our technical staff has specific expertise in developing our core properties. Additionally, members of our senior management team average over 27 years of operating experience in the Gulf of Mexico. We also own an extensive core focused seismic database covering approximately 5,670 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.

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.

Geographically Focused Properties in the Gulf of Mexico.  We operate geographically focused producing properties 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.

General Information on 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, 2012 which represent approximately 83% of our net proved reserves and 88% of our future net revenues, discounted at 10%.

Main Pass 61 Field.  We operate and have a 100% working interest in the Main Pass 61 field, located near the mouth of the Mississippi River in approximately 90 feet of water on Outer Continental Shelf (“OCS”) blocks Main Pass 60, 61, 62 and 63. The field was discovered by Pogo in 2000, and has produced in excess of 51 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 22 producing wells and three major production platforms located throughout the field. The field’s average net production for the quarter ended June 30, 2012 of 6.4 MBOE/Day (“MBOED”), accounted for approximately 13% of our net production for the quarter. Net proved reserves for the field, which is our largest field based upon net proved reserves, were 89% oil at June 30, 2012.

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 over a large anticlinal feature from 1,500 feet to 13,000 feet. The field has produced in excess of 376 MMBOE. There are six production platforms and 34 active and 30 shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2012 was 4.2 MBOED. Net proved reserves for the field were 84% oil at June 30, 2012. This field is the seventh largest oil field on the Gulf of Mexico Shelf.

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West Delta 30.  We operate 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 731 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, 2012 was 2.8 MBOED. Net proved reserves for the field were 80% oil at June 30, 2012. This field is the largest oil field on the Gulf of Mexico Shelf.

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 400 feet of water. The field was discovered by Gulf Oil in 1974. 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, 2012 was 2.2 MBOED. Net proved reserves for the field were 64% oil at June 30, 2012.

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 Mobil 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 74. Average net production from the complex for the quarter ended June 30, 2012 was 5.7 MBOED and accounted for approximately 12% of our net production for the quarter. Net proved reserves for the field were 69% oil at June 30, 2012.

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. In addition, we were the high bidder on South Timbalier Block 22 and received notice that the bid was accepted on August 9, 2012. The field was discovered by Gulf Oil in the late 1950s and has produced in excess of 326 MMBOE since production first began in 1957. 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 44 smaller structures located throughout the field. The field’s average net production for the quarter ended June 30, 2012 was 2.3 MBOED. Net proved reserves for the field were 84% oil at June 30, 2012. This field is the ninth largest oil field on the Gulf of Mexico Shelf.

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 16,000 feet in depth against the salt piercements. Radial faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 517 MMBOE. There are 15 production platforms and 48 active and 33 shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2012 was 10.6 MBOED and accounted for approximately 22% of our net production for the quarter. Net proved reserves for the field were 76% oil at June 30, 2012. This field is the fifth largest oil field on the Gulf of Mexico Shelf.

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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 142 MMBOE. There are five production platforms and 27 active and 17 shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2012 was 3.6 MBOED. Net proved reserves for the field were 69% oil at June 30, 2012.

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 6.1 MMBOE 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 has produced 2.5 MMBOE to date. The field’s average net production for the quarter ended June 30, 2012 was 1.2 MBOED. Net proved reserves for the field were 93% gas at June 30, 2012.

Ultra-Deep Trend Exploration and Development Activity

We participate with McMoRan Exploration Company in several prospects in the ultra-deep shelf and onshore area 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, we have also identified approximately 15 ultra-deep prospects in shallow water near existing infrastructure. In addition we will participate in three onshore ultra-deep prospects located in South Louisiana. From January 2008 through June 2012 we drilled the Blackbeard East, Lafitte, Blackbeard West, Blackbeard West No. 2 and Lineham Creek exploratory wells and completed delineation drilling at Davy Jones. Current sub-salt drilling plans include 2 to 3 exploratory wells. We expect to have sufficient cash flow from operations to fund our current commitments related to our ultra-deep trend exploration and development activity.

As previously reported, we have drilled two successful sub-salt wells in the Davy Jones field. The Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. The Davy Jones offset appraisal well (Davy Jones No. 2), which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect, and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. We expect to commence the completion of the Davy Jones No. 2 well in early 2013. The Davy Jones field involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). As of June 30, 2012, our investment in both wells in the Davy Jones field was approximately $111 million.

Davy Jones.  The Davy Jones No. 1 well on South Marsh Island Block 230 was successfully completed in March 2012 and work is ongoing to establish commercial production from the well. The perforation of the Wilcox “D” sand in March 2012 resulted in positive pressure build-up in the wellbore followed by a gas flare from the well. Initial samples indicated that the natural gas from the Wilcox “D” sand is high quality and contains low levels of CO2 and no H2S is present. Blockage from drilling fluid associated with initial drilling operations prevented the group from obtaining a measurable flow rate. Attempts to perforate the Wilcox “C” sand did not clear the blockage. In April 2012, the group commenced operations to remove the tubing from the well, clear the residual drilling fluid, and remove the perforating guns currently set across the Wilcox “F” sand to provide access to all of the Wilcox reservoirs (“A” through “F”) totaling 200 net feet. To maximize production from the well and enable effective formation penetrations, the group used electric wireline casing guns that are larger than the tubing guns used to perforate the Wilcox “C” and “D” sands. We expect the operations currently underway will enable a measurable flow rate during the first quarter of Fiscal 2013, followed by commercial production shortly thereafter. In June 2012, the operator successfully perforated 165 feet of Wilcox sands in the Davy Jones No.1 well with electric wireline casing guns. The operator expects to conduct a measurable flow test within the September 30, 2012 quarter.

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Blackbeard East.  The Blackbeard East ultra-deep exploration by-pass well was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. The Frio sands are the first hydrocarbon bearing Frio sands encountered either on the Gulf of Mexico (“GOM”) Shelf or in the deepwater offshore Louisiana. Pressure and temperature data below the salt weld between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. The operator holds the lease rights to South Timbalier Block 144 through August 17, 2012 and is submitting initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior. The operator plans to test and complete the upper Miocene sands during 2013 using conventional equipment and technologies. Additional plans for further development of the deeper zones continue to be evaluated. The group’s ability to preserve the interest in Blackbeard East will require approval from the Bureau of Safety and Environmental Enforcement of the development plans. Blackbeard East is located in 80 feet of water on South Timbalier Block 144. As of June 30, 2012, our investment in the well totaled approximately $50 million.

Lafitte.  The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Vicksburg, and Sparta carbonate. The Upper Eocene sands are the first hydrocarbon bearing Upper Eocene sands encountered either on the GOM Shelf or in the deepwater offshore Louisiana. The group is evaluating development options associated with these formations. As of June 30, 2012, our investment in the well totaled approximately $40 million.

Blackbeard West.  Information gained from the Blackbeard East and Lafitte wells will enable us 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 Blackbeard West No. 2 ultra-deep exploration well commenced drilling on November 25, 2011 and is drilling below 21,100 feet. The well, which is located on Ship Shoal Block 188 within the Blackbeard West unit, is targeting Miocene aged sands seen below the salt weld approximately 13 miles east at Blackbeard East and has a proposed total depth of 24,500 feet. In May 2012 the operator set a liner after the well encountered a high pressure gas flow immediately below the salt weld. If successful, completion could utilize conventional equipment and technologies. Our investment in both Blackbeard West wells totaled approximately $43 million at June 30, 2012.

Lineham Creek.  The Lineham Creek exploration prospect, operated by Chevron U.S.A. Inc., which is located onshore in Cameron Parish, Louisiana commenced drilling on December 31, 2011. The well, which is targeting Eocene and Paleocene objectives below the salt weld, is currently drilling below 20,700 feet towards a proposed total depth of 29,000 feet. As of June 30, 2012, our investment in the Lineham Creek well totaled approximately $8 million.

Reserve Estimation Procedures

The information included in this Form 10-K about our proved reserves represents evaluations prepared by Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”). NSAI has prepared evaluations on all of our proved reserves on a valuation basis 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, 2012. 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 Data.”

Internal Controls for Reserve Estimation

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

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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 are then reviewed by our Vice President of Corporate Development and members of our senior engineering staff 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.

The preparation of our reserve estimates is 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:

• a comparison of historical expenses is made to the lease operating costs in the reserve database;

• updated capital costs are supplied by our Operations Department;

• internal reserves estimates are reviewed by well and by area by engineering personnel. A variance by well to the previous year-end reserve report and quarter-end reserve estimate is used as a tool in this process;

• material reserve variances are discussed among the internal reservoir engineers and the Vice President of Corporate Development to ensure the best estimate of remaining reserves; and

• the internal reserves estimates are reviewed by senior management prior to publication.

Technologies Used in Reserve Estimation

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:

• the quality and quantity of available data and the engineering and geological interpretation of that data;

• estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;

• the accuracy of various mandated economic assumptions such as the future prices of oil and natural gas; and

• the judgment of the persons preparing the estimates.

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 31 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

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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 21 years.

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.

Summary of Oil and Gas Reserves at June 30, 2012

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the U.S. are based on evaluations prepared by third-party reservoir 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 discoveries are more imprecise than those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

	Summary of Oil and Gas Reserves as of June 30, 2012 Based on Average Fiscal-Year Prices
	Oil (MBbls)		Natural Gas (MMcf)		MBOE		Percent of Total Proved			PV-10 (in thousands)(1)
Proved
Developed		63.3		110.4		81.7		68	%	$	3,138,806
Undeveloped		21.5		98.6		37.9		32	%		1,158,639
Total Proved		84.8		209.0		119.6					4,297,445
Future Income taxes											1,377,363
10% discount											385,407
Future income taxes discounted at 10%											991,956
Standardized measure of future discounted net cash flows										$	3,305,489

(1) We refer to “PV-10” as the present value of estimated future net revenues of estimated proved reserves as calculated by NSAI using a discount rate of 10%. This amount includes projected revenues, estimated production costs and estimated future development costs. PV-10 is not a financial measure prescribed under generally accepted accounting principles (“GAAP”); therefore, the table reconciles this amount to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Management believes that the non-GAAP financial measure of PV-10 is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 is used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. We believe the use of this pre-tax measure is valuable because there are unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. The average oil price prior to quality, transportation fees, and regional price differentials was $115.08 per barrel of oil (calculated using the unweighted average first-day-of-the-month Heavy Louisiana Sweet posted prices during the 12-month period ending on June 30, 2012). The report forecasts crude oil and NGL production separately. The average realized adjusted product prices weighted by production over the remaining lives of the properties, used to determine future net revenues were $113.36 per barrel of oil and $56.92 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. The $113.36 per barrel realized oil price compares to an unweighted average first-day-of-the-month West

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Texas Intermediate price of $95.67 per barrel (differential of +$17.69 per barrel), and an unweighted average first-day-of-the-month Brent price of $112.49 per barrel (differential of +$0.87 per barrel)

For natural gas, the average Henry Hub price used was $3.15 per MMBtu, prior to adjustments for energy content, transportation fees, and regional price differentials (calculated using the unweighted average first-day-of-the-month Henry Hub spot price). The average adjusted realized gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $3.296 per MCF after adjusting for energy content, transportation fees, and regional price differentials.

Changes in Proved Reserves

Our total proved reserves increased 3.0 MMBOE from 116.6 MMBOE at June 30, 2011 to 119.6 MMBOE at June 30, 2012.

Development of Proved Undeveloped Reserves

Our proved undeveloped reserves at June 30, 2012 were 37.9 MMBOE. Future development costs associated with our proved undeveloped (“PUD”) reserves at June 30, 2012 totaled approximately $531.1 million. In the fiscal year ended June 30, 2012, we developed approximately 4% of our proved undeveloped reserves as of June 30, 2011, consisting of 5 gross, 4.9 net wells at a net cost of approximately $24.3 million. Four PUD’s were not converted into proved developed reserves within the five year requirement at June 30, 2012. Main Pass 61 OCS-G 16493 A-3 and Main Pass 73 B-19 ST are both sidetrack PUDs, but are still producing and cannot be drilled until the PDP zone in each well depletes. South Pass 49 OCS-G 2177 A-2 ST and A-10 ST were not converted because SP 49’s “A” platform is located in a mudslide area and had not been certified for drilling until May 2012, when Bureau of Safety and Environmental Enforcement certified that the platform met conditions for acceptance criteria.

The following table discloses our progress toward the conversion of proved undeveloped reserves during the fiscal year ended June 30, 2012.

	Crude Oil and Natural Gas			Future Development Costs
	(MBOE)			(In thousands)
Proved undeveloped reserves at June 30, 2011		35,020		$	406,649
Extensions and discoveries		8,041			185,266
Revisions of previous estimates		(1,490	)		(30,595	)
Reclassification of proved undeveloped(1)		(2,123	)		(5,889	)
Conversions to proved developed reserves		(1,517	)		(24,300	)
Total proved undeveloped reserves added		2,911			124,482
Proved undeveloped reserves at June 30, 2012		37,931		$	531,131

(1) Relates to the reclassification of proved undeveloped reserves to probable reserves due to the SEC five-year development rule.

Drilling Activity

The following table sets forth our drilling activity.

	Year Ended June 30,
	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Productive wells drilled
Development		13.0		10.4		10.0		6.0		3.0		1.5
Exploratory		—		—		4.0		1.0		3.0		0.6
Total		13.0		10.4		14.0		7.0		6.0		2.1
Non productive dry wells drilled
Development		1.0		0.1		1.0		0.3		1.0		1.0
Exploratory		2.0		1.3		3.0		1.3		3.0		1.6
Total		3.0		1.4		4.0		1.6		4.0		2.6

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Present Activities

As of June 30, 2012, ten gross wells, representing approximately 5.3 net wells, were being drilled.

Delivery Commitments

As of June 30, 2012, we had no delivery commitments.

Productive Wells

Our working interests in productive wells follow.

	June 30,
	2012				2011
	Gross		Net		Gross		Net
Natural Gas		93		40		88		56
Crude Oil		357		270		331		257
Total		450		310		419		313

Acreage

Working interests in developed and undeveloped acreage follow.

	June 30, 2012
	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Onshore		40,213		19,201		22,339		7,984		62,552		27,185
Offshore		328,748		220,301		201,940		70,580		530,688		290,881
Total		368,961		239,502		224,279		78,564		593,240		318,066

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

	Year Ending June 30,
	2013				2014				2015
	Gross		Net		Gross		Net		Gross		Net
Onshore		2,876		2,108		1,699		1,338		221		168
Offshore		45,760		16,947		29,598		24,918		75,447		13,583
Total		48,636		19,055		31,297		26,256		75,668		13,751

Capital Expenditures, Including Acquisitions and Costs Incurred

Property acquisition costs:

	Year Ended June 30,
	2012			2011		2010
	(In Thousands)
Oil and Gas Activities
Development	$	383,495		$	180,191	$	92,949
Exploration		183,397			98,133		51,030
Acquisitions		6,401			1,012,262		293,037
Administrative and other		3,778			2,909		1,133
Capital expenditures, including acquisitions		577,071			1,293,495		438,149
Asset retirement obligations and other, net		(55,399	)		205,702		17,996
Total costs incurred	$	521,672		$	1,499,197	$	456,145

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Oil and Gas Production and Prices

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

	Year Ended June 30,
	2012			2011			2010
Sales Volumes per Day
Natural gas (MMcf)		81.5			67.2			42.6
Crude oil (MBbls)		30.5			23.4			14.7
Total (MBOE)		44.1			34.6			21.8
Percent of BOE from crude oil		69	%		68	%		67	%
Average Sales Price
Natural gas per Mcf	$	2.97		$	4.15		$	4.47
Hedge gain per Mcf		0.94			1.54			2.68
Total natural gas per Mcf	$	3.91		$	5.69		$	7.15
Crude oil per Bbl	$	106.17		$	90.95		$	71.73
Hedge gain (loss) per Bbl		0.04			(6.80	)		0.75
Total crude oil per Bbl	$	106.21		$	84.15		$	72.48
Sales price per BOE	$	78.97		$	69.59		$	57.09
Hedge gain (loss) per BOE		1.77			(1.61	)		5.74
Total sales price per BOE	$	80.74		$	67.98		$	62.83

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, 2012. Our average daily production, average sales prices and production cost follow.

	Year Ended June 30,
	2012			2011			2010
Main Pass 61
Sales Volumes per Day
Natural gas (MMcf)		4.1			3.0			3.5
Crude oil (MBbls)		6.5			7.2			5.8
Total (MBOE)		7.2			7.7			6.4
Percent of BOE from crude oil		90	%		94	%		91	%
Average Sales Price
Natural gas per Mcf	$	2.91		$	4.44		$	4.99
Crude oil per Bbl	$	105.94		$	88.62		$	75.37
Production Costs per BOE	$	9.77		$	10.30		$	11.37

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Production Unit Costs

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

	Year Ended June 30,
	2012		2011		2010
Average Costs per BOE
Production costs
Lease operating expense
Insurance expense	$	1.77	$	2.21	$	3.48
Workover and maintenance		3.49		2.62		2.47
Direct lease operating expense		13.99		14.12		12.01
Total lease operating expense		19.25		18.95		17.96
Production taxes		0.45		0.26		0.53
Total production costs	$	19.70	$	19.21	$	18.49
Gathering and transportation	$	1.01	$	0.98		—
Depreciation, depletion and amortization rates	$	22.76	$	23.22	$	22.87

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 approximately 70 producing wells in 20 fields with net production on the date of sale of approximately 8 MMcf/d of natural gas and 285 Bbl/d of crude oil, or a total equivalent of 1.6 MBOE/d.

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.”

Marketing and Customers

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

Shell Trading Company (“Shell”) accounted for approximately 32%, 61% and 62% of our total oil and natural gas revenues during the years ended June 30, 2012, 2011 and 2010, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 37% and 22% of our total oil and natural gas revenues during the years ended June 30, 2012 and 2011, respectively. J.P. Morgan Ventures Energy Corporation (“J.P. Morgan”) accounted for 18% of our total oil and natural gas revenues during the year ended June 30, 2012. 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, ExxonMobil and or J.P. Morgan curtailed their purchases.

We transport a portion 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.

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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.

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

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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 calendar years, are required to post certain information 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 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 the EPAct of 1992, petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of the 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 the EPAct of 1992 in either the economic circumstances of the oil pipeline or

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in the nature of the services provided that were a basis for the rate. The EPAct of 1992 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 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 Regulations.  Our operations on federal oil and gas leases in the Gulf of Mexico are subject to regulation by the BSEE and the Bureau of Ocean Energy Management (BOEM”), successor agencies to the Minerals Management Service. These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act (“OCSLA”). These laws and regulations are subject to change, and many new requirements were imposed by the BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency, (the “EPA”), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM exempts the lessee from such obligations. The cost of such bonds or other surety can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. Under certain circumstances, the Bureau of Safety and Environmental Enforcement (“BSEE”), a new federal agency created to enforce compliance with safety and environmental rules applicable to OCS activities, may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.

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, ongoing 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.

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, the establishment of financial

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assurance requirements for oil spill response costs and the decommissioning of offshore facilities 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:

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

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

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

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

• Endangered Species Act, Marine Protected Areas, Marine Mammal Protection Act, Migratory Bird Treaty Act, which governs the protection of animals, flora and fauna;

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

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

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

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

Oil Pollution Act.  The Oil Pollution Act of 1990 (“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 OCS. The OPA subjects owners 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 to surface waters and natural resource damages. Although defenses exist to the liability imposed by OPA, they are limited. 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. 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. In any event, if there were to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

Climate Change.  In December 2009, the U.S. Environmental Protection Agency (the “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 Clean Air Act (“CAA”). The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, 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 large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual 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.

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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 produce. 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.

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.

Employees

We had 215 employees at June 30, 2012. At June 30, 2012, we had no employees represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are good.

Available Information

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

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.

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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:

• fires;

• explosions;

• blow-outs and surface cratering;

• uncontrollable flows of gas, oil and formation water;

• natural disasters, such as hurricanes and other adverse weather conditions;

• pipe, cement, subsea well or pipeline failures;

• casing collapses;

• mechanical difficulties, such as lost or stuck oil field drilling and service tools;

• abnormally pressured formations; and

• environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:

• injury or loss of life;

• severe damage to and destruction of property, natural resources and equipment;

• pollution and other environmental damage;

• clean-up responsibilities;

• regulatory investigations and penalties;

• suspension of our operations; and

• repairs to resume operations.

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:

• subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate; and

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• result in our dependency upon a single or limited number of hydrocarbon basins.

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:

• severe weather, such as hurricanes and other adverse weather conditions;

• delays or decreases in production, the availability of equipment, facilities or services;

• delays or decreases in the availability of capacity to transport, gather or process production; and/or

• changes in the regulatory environment.

For example, the oil and gas properties that we acquired in April 2006 were damaged by both Hurricanes Katrina and Rita, and again by Hurricanes Gustav and Ike and the oil and gas properties that we acquired in June 2007 were damaged by Hurricanes Katrina and Rita. 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 all of the operating risks to which our business is exposed.”

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, 2012 and June 30, 2012 ranged from a high of $109.77 to a low of $77.69 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2012 to June 30, 2012 ranged from a high of $3.10 to a low of $1.91. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

• domestic and foreign supplies of oil and natural gas;

• price and quantity of foreign imports of oil and natural gas;

• actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

• level of consumer product demand, including as a result of competition from alternative energy sources;

• level of global oil and natural gas exploration and productivity;

• domestic and foreign governmental regulations;

• level of global oil and natural gas inventories;

• political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;

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• weather conditions;

• technological advances affecting oil and natural gas production and consumption;

• overall U.S. and global economic conditions; and

• price and availability of alternative fuels.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us having to make 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, 2012 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, 2012, we reduced our proved reserve estimates by 2.1 MMBOE due to the five year development rule.

As of June 30, 2012, approximately 32% of our total proved reserves were undeveloped and approximately 16% 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 17% 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.

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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.

Ultra-deep trend wells may require equipment that may delay development and incur longer drilling times, which may increase costs.

We have participated in seven shallow-water ultra-deep trend wells to date. Of these wells, one has been temporarily abandoned pending further evaluation, three are temporarily abandoned pending facilities and completions, two are currently drilling and one is currently being tested. 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.

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

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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 BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the

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

• supply of and demand for natural gas and oil;

• actual prices we receive for natural gas and oil;

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

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

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

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

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute exploration and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services may increase or decrease depending on the demand for services by other oil and gas companies. 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 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

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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 85% 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:

• the timing and amount of capital expenditures;

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

• the operator’s expertise and financial resources;

• approval of other participants in drilling wells;

• selection of technology; and

• the rate of production of the reserves.

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.

We sell the majority of our production to three customers.

Shell accounted for approximately 32%, ExxonMobil accounted for approximately 37% and J.P. Morgan accounted for approximately 18% our total oil and natural gas revenues during the year ended June 30, 2012. Our inability to continue to sell our production to Shell, ExxonMobil and or J.P. Morgan, 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

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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 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. 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.

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.

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 our revolving credit facility 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.

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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:

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

• production is less than expected;

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

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

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.

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:

• operating a larger organization;

• coordinating geographically disparate organizations, systems and facilities;

• integrating corporate, technological and administrative functions;

• diverting management’s attention from other business concerns;

• diverting financial resources away from existing operations;

• an increase in our indebtedness; and

• potential environmental or regulatory liabilities and title problems.

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

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

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

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

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If we are unable to effectively manage the commodity price risk of our production if energy prices fall, we may not realize the anticipated cash flows from our acquisitions.

Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Therefore, there is the possibility that we may be unable to find counterparties willing to enter into derivative arrangements with us or be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we fail to manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves.

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:

• acceptable prices for available properties;

• amounts of recoverable reserves;

• estimates of future oil and natural gas prices;

• estimates of future exploratory, development and operating costs;

• estimates of the costs and timing of plugging and abandonment; and

• estimates of potential environmental and other liabilities.

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, 2012, we had total indebtedness of $1,018.3 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:

• impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general business activities or other purposes;

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

• result in higher interest expense in the event of increases in interest rates since some of our debt is at variable rates of interest;

• have a material adverse effect if we fail to comply with financial and restrictive covenants in any of our debt agreements, including an event of default if such event is not cured or waived;

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

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

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

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

We 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, 2012, we and our subsidiary guarantors collectively had approximately $18.3 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:

• refinance all or a portion of our debt;

• obtain additional financing;

• sell some of our assets or operations;

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

• revise or delay our strategic plans.

If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure 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:

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• incur dividend or other payment obligations;

• incur indebtedness and issue preferred stock; or

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

If we breach any of these covenants, a default could occur. A default, if not waived, would entitle certain of our debt holders to declare all amounts borrowed under the breached indenture to become immediately due and payable, which could also cause the acceleration of obligations under certain other agreements and the termination of our credit facility. In the event of acceleration of our outstanding indebtedness, we cannot assure 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.

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, 2012, we had no borrowings under our revolving credit facility and our 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 2012. If the borrowing base is reduced or maintained, 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

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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.

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.

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. Our current borrowing base under our revolving credit facility is $750 million. 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 also 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.

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

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

• require the acquisition of a permit before drilling commences;

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

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

• impose substantial liabilities for pollution resulting from operations.

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

• the imposition of administrative, civil and/or criminal penalties;

• incurring investigatory or remedial obligations; and

• the imposition of injunctive relief, which could limit or restrict our operations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse

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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 shareholders 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.

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.

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.

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.

The April 2010 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. 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, a substantial portion of which is in the deep water of the Gulf of Mexico.

In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BSEE, 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, 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. However, legislation has been proposed in the U.S. Congress to increase the minimum level of financial responsibility to $300 million or more. 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 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 BSEE 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 BSEE issued a series of Notice to Lessees (“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:

• The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.

• The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.

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• The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.

• The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

Since the adoption of these new regulatory requirements, BSEE 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 BSEE 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 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 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

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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 adoption of financial reform 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, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act, the CFTC has issued final 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. 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 certain 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 final rules will be phased in over time according to a specified schedule which is dependent on the finalization of certain other rules to be promulgated jointly by the CFTC and the SEC. The Dodd-Frank Act 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.

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

To cover the various obligations of lessees on the OCS of the U.S. Gulf of Mexico, the BOEM generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. While we believe that we are currently exempt from the supplemental bonding requirements of the BOEM, the BOEM could re-evaluate our plugging obligations and increase them which could cause us to lose our exemption. The cost of these bonds or other surety could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. Such letter of credit would likely be issued under our credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. The cost of compliance with these supplemental bonding requirements could materially and adversely affect our financial condition, cash flows and results of operations.

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

34

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 Budget for Fiscal Year 2013 sent to Congress by President Obama on February 13, 2012, contains recommendations that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. Several bills have been introduced in Congress that would implement these proposals. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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.

35

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

Our by-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 by-laws that could delay or prevent a change in management or change in control include:

• the board is permitted to issue preferred shares and to fix the price, rights, preferences, privileges and restrictions of the preferred shares without any further vote or action by our shareholders;

• election of our directors is staggered, meaning that the members of only one of three classes of our directors are elected each year;

• shareholders have limited ability to remove directors; and

• in order to nominate directors at shareholder meetings, shareholders must provide advance notice and furnish certain information with respect to the nominee and any other information as may be reasonably required by the Company.

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 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).

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information regarding our properties is included in Item 1. Business of this Form 10-K.

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 consolidated financial position, results of operations or cash flows.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

Market Information for Common Stock

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 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
Fiscal 2012
First Quarter		34.89		21.48
Second Quarter		32.05		20.27
Third Quarter		39.03		31.63
Fourth Quarter		37.96		26.41

As of July 31, 2012, there were approximately 329 holders of record of our common stock.

Dividend Information

On May 2, 2012, our Board of Directors approved payment of a quarterly cash dividend of $0.07 per share to the holders of the Company’s common stock. The quarterly dividend was paid on June 15, 2012 to shareholders of record on June 1, 2012.

On July 18, 2012, our Board of Directors approved payment of a quarterly cash dividend of $0.07 per share to the holders of the Company’s common stock. The quarterly dividend will be paid on September 14, 2012 to shareholders of record on August 31, 2012.

Purchases of Equity Securities

Repurchases of Common Stock

The following table presents information about repurchases of our common stock during the quarter ended June 30, 2012:

Period	Total Number of Shares Purchased(a)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs
April 1, 2012 through April 30, 2012		—		—
May 1, 2012 through May 31, 2012		75,000	$	34.94
June 1, 2012 through June 30, 2012		—		—
Total		75,000	$	34.94

(a) Reflects the number of shares of common stock purchased through open-market transactions for future issuances to employees under our benefit plans.

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Item 6.  Selected Financial Data

The selected consolidated financial data set forth below should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the consolidated financial statements and notes to those consolidated financial statements included elsewhere in this Form 10-K.

	Year Ended June 30,
	2012			2011			2010			2009			2008
	(In Thousands, Except per Share Amounts)
Income Statement Data
Revenues	$	1,303,403		$	859,370		$	498,931		$	433,830		$	643,232
Depreciation, Depletion and Amortization (“DD&A”)		367,463			293,479			181,640			217,207			307,389
Impairment of Oil and Gas Properties		—			—			—			576,996			—
Operating Income (Loss)		483,284			208,923			102,047			(517,217	)		143,600
Other Income (Expense) – Net		(108,811	)		(132,006	)		(58,483	)		(76,751	)		(101,857	)
Net Income (Loss)		335,827			64,655			27,320			(571,629	)		26,869
Basic Earnings (Loss) per Common Share	$	4.10		$	0.42		$	0.56		$	(19.77	)	$	1.57
Diluted Earnings (Loss) per Common Share	$	3.85		$	0.42		$	0.56		$	(19.77	)	$	1.49
Cash Flow Data
Provided by (Used in)
Operating Activities	$	785,514		$	387,725		$	121,213		$	245,835		$	414,647
Investing Activities
Acquisitions		(6,401	)		(1,012,262	)		(293,037	)		—			(40,016	)
Investment in properties		(570,670	)		(281,233	)		(145,112	)		(266,012	)		(357,173	)
Other		7,478			38,423			53,989			2,935			(296	)
Total Investing Activities		(569,593	)		(1,255,072	)		(384,160	)		(263,077	)		(397,485	)
Financing Activities		(127,241	)		881,530			188,246			(62,795	)		132,016
Increase (Decrease) in Cash	$	88,680		$	14,183		$	(74,701	)	$	(80,037	)	$	149,178
Dividends Paid per Average Common Share	$	0.07			—			—		$	0.075			—

	June 30,
	2012		2011		2010		2009		2008
	(In Thousands)
Balance Sheet Data
Total Assets	$	3,130,947	$	2,798,860	$	1,566,491	$	1,328,662	$	2,049,931
Long-term Debt Including Current Maturities		1,018,344		1,113,387		774,600		862,827		952,222
Stockholders’ Equity		1,405,840		946,697		436,561		127,500		374,585
Common Shares Outstanding		79,147		76,204		50,637		29,150		28,987

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	Year Ended June 30,
Operating Highlights	2012			2011			2010			2009			2008
	(In Thousands, Except per Unit Amounts)
Operating revenues
Crude oil sales	$	1,186,193		$	777,869		$	383,928		$	278,014		$	484,552
Natural gas sales		88,608			101,815			69,399			113,156			237,628
Hedge gain (loss)		28,602			(20,314	)		45,604			42,660			(78,948	)
Total revenues		1,303,403			859,370			498,931			433,830			643,232
Percent of operating revenues from crude oil
Prior to hedge gain (loss)		93	%		88	%		85	%		71	%		67	%
Including hedge gain (loss)		91	%		84	%		78	%		68	%		62	%
Operating expenses
Lease operating expense
Insurance expense		28,521			27,876			27,603			19,188			18,218
Workover and maintenance		56,413			33,095			19,630			15,930			22,397
Direct lease operating expense		225,881			178,507			95,379			87,032			102,244
Total lease operating expense		310,815			239,478			142,612			122,150			142,859
Production taxes		7,261			3,336			4,217			5,450			8,686
Gathering and transportation		16,371			12,499			—			—			—
Depreciation, depletion and amortization		367,463			293,479			181,640			217,207			307,389
Impairment of oil and gas properties		—			—			—			576,996			—
General and administrative		86,276			75,091			49,667			24,756			26,450
Other – net		31,933			26,564			18,748			4,488			14,248
Total operating expenses		820,119			650,447			396,884			951,047			499,632
Operating income (loss)	$	483,284		$	208,923		$	102,047		$	(517,217	)	$	143,600
Sales volumes per day
Natural gas (MMcf)		81.5			67.2			42.6			47.9			75.7
Crude oil (MBbls)		30.5			23.4			14.7			11.4			13.5
Total (MBOE)		44.1			34.6			21.8			19.3			26.2
Percent of sales volumes from crude oil		69	%		68	%		67	%		59	%		52	%
Average sales price
Natural gas per Mcf	$	2.97		$	4.15		$	4.47		$	6.48		$	8.57
Hedge gain per Mcf		0.94			1.54			2.68			1.60			0.34
Total natural gas per Mcf	$	3.91		$	5.69		$	7.15		$	8.08		$	8.91
Crude oil per Bbl	$	106.17		$	90.95		$	71.73		$	67.06		$	97.72
Hedge gain (loss) per Bbl		0.04			(6.80	)		0.75			3.56			(17.82	)
Total crude oil per Bbl	$	106.21		$	84.15		$	72.48		$	70.62		$	79.90
Total hedge gain (loss) per BOE	$	1.77		$	(1.61	)	$	5.74		$	6.04		$	(8.24	)
Operating revenues per BOE	$	80.74		$	67.98		$	62.83		$	61.47		$	67.16
Operating expenses per BOE
Lease operating expense
Insurance expense		1.77			2.21			3.48			2.72			1.90
Workover and maintenance		3.49			2.62			2.47			2.26			2.34
Direct lease operating expense		13.99			14.12			12.01			12.33			10.68
Total lease operating expense per BOE		19.25			18.95			17.96			17.31			14.92
Production taxes		0.45			0.26			0.53			0.77			0.91
Impairment of oil and gas properties		—			—			—			81.75			—
Gathering and transportation		1.01			0.98			—			—			—
Depreciation, depletion and amortization		22.76			23.22			22.87			30.78			32.09
General and administrative		5.34			5.94			6.25			3.51			2.76
Other – net		1.98			2.10			2.36			0.64			1.49
Total operating expenses per BOE		50.79			51.45			49.97			134.76			52.17
Operating income (loss) per BOE	$	29.95		$	16.53		$	12.86		$	(73.29	)	$	14.99

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	Quarter Ended
Operating Highlights	June 30, 2012			Mar. 31, 2012			Dec. 31, 2011			Sept. 30, 2011			June 30, 2011
	(In Thousands, Except per Unit Amounts)
Operating revenues
Crude oil sales	$	314,639		$	315,723		$	306,064		$	249,767		$	270,252
Natural gas sales		19,657			19,154			21,659			28,138			31,875
Hedge gain (loss)		7,650			1,119			12,855			6,978			(19,346	)
Total revenues		341,946			335,996			340,578			284,883			282,781
Percent of operating revenues from crude oil
Prior to hedge gain (loss)		94	%		94	%		93	%		90	%		89	%
Including hedge gain (loss)		92	%		93	%		91	%		87	%		85	%
Operating expenses
Lease operating expense
Insurance expense		6,825			7,138			7,096			7,462			8,814
Workover and maintenance		21,070			15,885			12,805			6,653			17,251
Direct lease operating expense		59,306			55,424			54,233			56,918			59,557
Total lease operating expense		87,201			78,447			74,134			71,033			85,622
Production taxes		2,414			1,499			1,174			2,174			1,205
Gathering and transportation		4,358			2,465			3,395			6,153			6,868
DD&A		106,644			88,448			87,568			84,803			85,179
General and administrative		19,733			25,075			22,147			19,321			17,553
Other – net		5,186			13,257			14,174			(684	)		7,730
Total operating expenses		225,536			209,191			202,592			182,800			204,157
Operating income	$	116,410		$	126,805		$	137,986		$	102,083		$	78,624
Sales volumes per day
Natural gas (MMcf)		92.5			83.7			72.8			77.0			83.0
Crude oil (MBbls)		32.2			31.4			30.6			28.0			28.3
Total (MBOE)		47.6			45.3			42.7			40.8			42.1
Percent of sales volumes from crude oil		68	%		69	%		72	%		69	%		67	%
Average sales price
Natural gas per Mcf	$	2.34		$	2.52		$	3.23		$	3.97		$	4.22
Hedge gain per Mcf		0.55			0.54			1.43			1.39			1.37
Total natural gas per Mcf	$	2.89		$	3.06		$	4.66		$	5.36		$	5.59
Crude oil per Bbl	$	107.34		$	110.54		$	108.80		$	97.11		$	105.12
Hedge gain (loss) per Bbl		1.03			(1.05	)		1.17			(1.11	)		(11.53	)
Total crude oil per Bbl	$	108.37		$	109.49		$	109.97		$	96.00		$	93.59
Total hedge gain (loss) per BOE	$	1.77		$	0.27		$	3.27		$	1.86		$	(5.05	)
Operating revenues per BOE	$	78.90		$	81.43		$	86.67		$	75.91		$	73.85
Operating expenses per BOE
Lease operating expense
Insurance expense		1.57			1.73			1.81			1.99			2.30
Workover and maintenance		4.86			3.85			3.26			1.77			4.51
Direct lease operating expense		13.68			13.43			13.80			15.17			15.55
Total lease operating expense per BOE		20.11			19.01			18.87			18.93			22.36
Production taxes		0.56			0.36			0.30			0.58			0.31
Gathering and transportation		1.01			0.60			0.86			1.64			1.79
DD&A		24.61			21.44			22.28			22.60			22.24
General and administrative		4.55			6.08			5.64			5.15			4.58
Other – net		1.20			3.22			3.60			(0.18	)		2.01
Total operating expenses per BOE		52.04			50.71			51.55			48.72			53.29
Operating income per BOE	$	26.86		$	30.72		$	35.12		$	27.19		$	20.56

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

The following discussion and analysis should be read in conjunction with our accompanying consolidated financial statements and the notes to those consolidated 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. Known material factors that could cause or contribute to such differences include 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 trend for potential oil and gas reserves. We are the third largest oil producer on the Gulf of Mexico Shelf with interest in six of the eleven largest oil fields in the Gulf of Mexico Shelf.

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, 2012, excluding acquisitions, approximately 33% of our capital expenditures were associated with the exploitation of existing properties.

At June 30, 2012, our total proved reserves were 119.6 MMBOE of which 71% were oil and 68% were classified as proved developed. We operated or had an interest in 450 gross producing wells on 239,502 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 85% of our proved reserves are on properties operated by us. We have a seismic database covering approximately 5,670 square miles, primarily focused on our existing operations. This database has helped us identify approximately 194 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.  In April 2006, we closed on the purchase of 100% 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.  In July 2006, we closed on the purchase of certain oil and natural gas properties in Louisiana from affiliates of Castex. Our cash cost of the acquisition was approximately $312.5 million.

Pogo Properties.  In June 2007, we closed on the purchase of Pogo Properties from Pogo for approximately $415.1 million.

Mit Acquisition.  In December 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

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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.  In December 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.

Ultra-Deep Trend Exploration and Development Activity

We participate with McMoRan Exploration Company in several prospects in the ultra-deep shelf and onshore area 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, we have also identified approximately 15 ultra-deep prospects in shallow water near existing infrastructure. In addition, we will participate in three onshore ultra-deep prospects located in South Louisiana. The ultra-deep drilling plans in calendar years 2008 through 2012 included the Blackbeard East, Lafitte, Blackbeard West, Blackbeard West No. 2 and Lineham Creek exploratory wells and delineation drilling at Davy Jones. Near -term sub-salt drilling plans include 2 to 3 exploratory wells. We expect to have more than sufficient cash flow from operations to fund our current commitments related to our ultra-deep trend exploration and development activity.

As previously reported, we have drilled two successful sub-salt wells in the Davy Jones field. The Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. The Davy Jones offset appraisal well (Davy Jones No. 2), which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect, and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. We expect to commence the completion of the Davy Jones No. 2 well in the second half of 2012. The Davy Jones field involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). As of June 30, 2012, our investment in both wells in the Davy Jones field totaled approximately $111 million.

Davy Jones.  The Davy Jones No. 1 well on South Marsh Island Block 230 was successfully completed in March 2012 and work is ongoing to establish commercial production from the well. The perforation of the Wilcox “D” sand in March 2012 resulted in positive pressure build-up in the wellbore followed by a gas flare from the well. Initial samples indicated that the natural gas from the Wilcox “D” sand is high quality and contains low levels of CO2 and no H2S is present. Blockage from drilling fluid associated with initial drilling operations prevented the group from obtaining a measurable flow rate. Attempts to perforate the Wilcox “C” sand did not clear the blockage. In April 2012, the group commenced operations to remove the tubing from the well, clear the residual drilling fluid, and remove the perforating guns currently set across the Wilcox “F” sand to provide access to all of the Wilcox reservoirs (“A” through “F”) totaling 200 net feet. To maximize production from the well and enable effective formation penetrations, the group plans to use electric wireline casing guns that are larger than the tubing guns used to perforate the Wilcox “C” and “D” sands. We expect the operations currently underway will enable a measurable flow rate during the first quarter of Fiscal 2013, followed by commercial production shortly thereafter. In June 2012, the operator successfully perforated 165 feet of Wilcox sands in the Davy Jones No.1 well with electric wireline casing guns. On July 13, 2012 the operator commenced operations to run production tubing and expects to conduct a measurable flow test within the September 30, 2012 quarter.

Blackbeard East.  The Blackbeard East ultra-deep exploration by-pass well was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. The Frio sands are the first hydrocarbon bearing Frio sands encountered either on the GOM Shelf or in the

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deepwater offshore Louisiana. Pressure and temperature data below the salt weld between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. The operator holds the lease rights to South Timbalier Block 144 through August 17, 2012 and is submitting initial development plans for Blackbeard East to the BSEE. The operator plans to test and complete the upper Miocene sands during 2013 using conventional equipment and technologies. Additional plans for further development of the deeper zones continue to be evaluated. The group’s ability to preserve the interest in Blackbeard East will require approval from the BSEE of the development plans. Blackbeard East is located in 80 feet of water on South Timbalier Block 144. As of June 30, 2012, our investment in the well totaled approximately $50 million.

Lafitte.  The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Vicksburg, and Sparta carbonate. The Upper Eocene sands are the first hydrocarbon bearing Upper Eocene sands encountered either on the GOM Shelf or in the deepwater offshore Louisiana. The group is evaluating development options associated with these formations. As of June 30, 2012, our investment in the well totaled approximately $40 million.

Blackbeard West.  Information gained from the Blackbeard East and Lafitte wells will enable us 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 Blackbeard West No. 2 ultra-deep exploration well commenced drilling on November 25, 2011 and is drilling below 21,100 feet. The well, which is located on Ship Shoal Block 188 within the Blackbeard West unit, is targeting Miocene aged sands seen below the salt weld approximately 13 miles east at Blackbeard East and has a proposed total depth of 24,500 feet. In May 2012 the operator set a liner after the well encountered a high pressure gas flow immediately below the salt weld. If successful, completion could utilize conventional equipment and technologies. Our investment in both Blackbeard West wells totaled approximately $43 million at June 30, 2012.

Lineham Creek.  The Lineham Creek exploration prospect, operated by Chevron U.S.A. Inc., which is located onshore in Cameron Parish, Louisiana commenced drilling on December 31, 2011. The well, which is targeting Eocene and Paleocene objectives below the salt weld, is currently drilling below 20,700 feet towards a proposed total depth of 29,000 feet. As of June 30, 2012, our investment in the Lineham Creek well totaled approximately $8 million.

Known Trends and Uncertainties

Continued Volatility in Commodity Price Environment.  Commodity prices are one of our key drivers of earnings generation and net operating cash flow and are affected by many factors that are outside of our control. 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. We actively seek to mitigate this volatility through the implementation of a hedging program that covers a portion of our total anticipated production through December 2014. See Note 9 of Notes to Consolidated Financial Statements in this Annual Report for a detailed discussion of our hedging program.

Ongoing Disruptions in Global Financial Markets.  Multiple events during 2009 through 2012 involving numerous countries and financial institutions impacted liquidity within the capital markets throughout the United States and around the world. 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 and stability to the financial sector, access to capital markets has remained somewhat constrained. While we currently expect to fund our capital program from existing cash flow from operations, we may be required to issue equity or debt to maintain adequate liquidity to implement our capital program. To extent that access to capital markets remains constrained, we expect that our ability to raise debt and equity capital, and the terms on which we can raise such capital, may be somewhat restricted.

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Oil Spill Response Plan.  We maintain a Regional Oil Spill Response Plan (the “Plan”) that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are generally approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. We believe the Plan specifications are consistent with the requirements set forth by the BSEE. Additionally, these plans are tested and drills are conducted periodically at all levels of the Company.

The Company has contracted with an emergency and spill response management consultant, to provide management expertise, personnel and equipment, under the supervision of the Company, in the event of an incident requiring a coordinated response. Additionally, the Company is a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the GOM and has capabilities to simultaneously respond to multiple spills. CGA has chartered its marine equipment to the Marine Spill Response Corporation (“MSRC”), a private, not-for-profit marine spill response organization which is funded by the Marine Preservation Association, a member-supported, not-for-profit organization created to assist the petroleum and energy-related industries by addressing problems caused by oil spills on water. In the event of a spill, MSRC mobilizes appropriate equipment to CGA members. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies.

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 Trend Exploration and Development.  We have participated in seven ultra-deep wells to date. Of these wells, one has been temporarily abandoned pending further evaluation, three are temporarily abandoned pending facilities and completions, two are currently drilling and one is currently being tested. These projects have similar geological characteristics as deepwater prospects with a potential for significant reserves. The shallow water ultra-deep trend 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. The shallow water ultra-deep is considered in the industry as Ultra High Pressure High Temperature, or U-HPHT. Generally this refers to pressures above 15,000 psig and temperatures above 300F. The U-HPHT in the play range from 400F to 474F, and bottom hole pressures from 26,500 psig to over 30,000 psig. Completion equipment has been designed to handle surface pressures to 25,000 psig and have been tested to 37,500 psig. There were 18 new technologies developed for this project which went through extensive design reviews, computational analysis, and finally physical testing to meet requirements for use in U-HPHT wells. All equipment is currently qualified to 25,000 psig and 450F. Work is ongoing for qualifying some of the same equipment for 30,000 psig surface. We target to spend less than 10% of our budgeted cash flow on our exploration activities on the ultra-deep. Based on the results of these wells, our proved reserves may vary from our current 71% oil composition.

Results of Operations

The data presented below excludes results from the (1) ExxonMobil Acquisition for periods prior to the December 17, 2010 closing date and (2) MitEnergy Acquisition for periods prior to November 20, 2009, the date that we gained control of the assets acquired and liabilities assumed.

Year Ended June 30, 2012 Compared With the Year Ended June 30, 2011

Our consolidated net income available for common stockholders was $316.7 million or $3.85 diluted per common share (“per share”) in fiscal 2012 as compared to consolidated net income available for common stockholders of $27.7 million or $0.42 diluted income per share in fiscal 2011. This improvement is primarily due to higher crude oil prices and sales volumes partially offset by lower natural gas sales prices and higher costs.

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Sales Price and Volume Variances

	Year Ended June 30,												Increase (Decrease)
	2012			2011			Increase (Decrease)
													(In Thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)	$	106.21		$	84.15		$	22.06			26	%	$	246,560
Natural gas sales prices (per Mcf)		3.91			5.69			(1.78	)		(31	)%		(53,085	)
Total price variance														193,475
Volume Variance
Crude oil sales volumes (MBbls)		11,172			8,553			2,619			31	%		220,388
Natural gas sales volumes (MMcf)		29,823			24,533			5,290			22	%		30,170
BOE sales volumes (MBOE)		16,143			12,642			3,501			28	%
Percent of BOE from crude oil		69	%		68	%
Total volume variance														250,558
Total price and volume variance													$	444,033

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

Revenue Variances

	Year Ended June 30,
	2012		2011		Increase (Decrease)
			(In Thousands)
Crude oil	$	1,186,631	$	719,683	$	466,948			65	%
Natural gas		116,772		139,687		(22,915	)		(16	)%
Total revenues	$	1,303,403	$	859,370	$	444,033			52	%

Oil and Natural Gas Revenues

Our consolidated revenues increased $444.0 million in fiscal 2012. 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 $193.5 million in fiscal 2012. Average natural gas prices, including a $0.94 realized gain per Mcf related to hedging activities, decreased $1.78 per Mcf during fiscal 2012, resulting in decreased revenues of $53.1 million. Average crude oil prices, including a $0.04 realized gain per barrel related to hedging activities, increased $22.06 per barrel in fiscal 2012, resulting in increased revenues of $246.6 million. Commodity prices are affected by many factors that are outside of our control. Commodity prices we received during fiscal 2012 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 2012 resulted in increased revenues of $250.6 million. Crude oil sales volumes increased 2,619 MBbls in fiscal 2012, resulting in higher revenues of $220.4 million. The increase in crude oil sales volumes in fiscal 2012 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 5,290 MMcf in fiscal 2012, resulting in improved revenues of $30.2 million. The increase in natural gas sales volumes in fiscal 2012 was primarily due to the ExxonMobil Acquisition coupled with the results of our capital program partially offset by natural decline.

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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
	2012						2011
	Amount			Per BOE			Amount			Per BOE
	(In Thousands, except per unit amounts)
Costs and expenses
Lease operating expense
Insurance expense	$	28,521		$	1.77		$	27,876		$	2.21		$	645
Workover and maintenance		56,413			3.49			33,095			2.62			23,318
Direct lease operating expense		225,881			13.99			178,507			14.12			47,374
Total lease operating expense		310,815			19.25			239,478			18.95			71,337
Production taxes		7,261			0.45			3,336			0.26			3,925
Gathering and transportation		16,371			1.01			12,499			0.98			3,872
DD&A		367,463			22.76			293,479			23.22			73,984
Accretion of asset retirement obligation		39,161			2.43			32,127			2.54			7,034
General and administrative expense		86,276			5.34			75,091			5.94			11,185
Gain on derivative financial instruments		(7,228	)		(0.45	)		(5,563	)		(0.44	)		(1,665	)
Total costs and expenses	$	820,119		$	50.79		$	650,447		$	51.45		$	169,672
Other (income) expense
Other (income) expense – other	$	(71	)	$	—		$	26,157		$	2.07		$	(26,228	)
Interest expense		108,882			6.74			105,849			8.37			3,033
Total other (income) expense	$	108,811		$	6.74		$	132,006		$	10.44		$	(23,195	)

Costs and expenses increased $169.7 million in fiscal 2012. This increase in costs and expenses was due in part to the ExxonMobil Acquisition which increased production related expenses in fiscal 2012 coupled with higher general and administrative expense. Below is a discussion of costs and expenses.

Lease operating expense increased $71.3 million in fiscal 2012 compared to fiscal 2011. 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.

Gathering and transportation expense increased $3.9 million in fiscal 2012 compared to fiscal 2011. This increase was primarily due to increased pipeline operations attributed to a full year of the ExxonMobil properties.

DD&A expense increased $73.9 million primarily due to higher equivalent production ($79.7) million as result of the ExxonMobil Acquisition partially offset by a lower DD&A rate ($5.8 million).

Accretion of asset retirement obligations increased $7.0 million primarily as a result of the increase in additional asset retirement obligations acquired during fiscal 2012.

The increase in gain on derivative financial instruments in fiscal 2012 compared to fiscal 2011 of $1.7 million is principally due to the turnaround related to the net price ineffectiveness of our hedged crude oil and natural gas contracts.

Production taxes increased $3.9 million primarily as a result of higher onshore production.

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General and administrative expense increased $11.2 million in fiscal 2012 principally as a result of higher compensation expense related to Restricted and Performance Units due to our rising common stock price.

Other (income) expense decreased $23.2 million in fiscal 2012 as compared to fiscal 2011. This decrease was primarily due to the items discussed below.

Other (income) expense — other decreased $26.2 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. Interest expense increased $3.0 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 19%, from $8.37/BOE to $6.74/BOE.

Income Tax Expense

Income tax expense increased $26.4 million in fiscal 2012 compared to fiscal 2011 primarily due to the primarily due to the increase in pre-tax income. Approximately 24 percent of the income tax expense consists of U.S. withholding taxes provided at a 30 percent rate on outbound intercompany interest accrued during the year. The effective income tax rate for fiscal 2012 decreased from fiscal 2011 from 16% to 10%. The decrease in the effective tax rate from fiscal year 2011 of 16% to 10.3% in 2012 is due to the additional release of the valuation allowance against the current tax on increased U.S. operating income.

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

Our consolidated net income available for common stockholders was $27.7 million or $0.42 diluted per share in fiscal 2011 as compared to consolidated net 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.

Sales Price and Volume Variances

	Year Ended June 30,												Increase (Decrease)
	2011			2010			Increase (Decrease)
													(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

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

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Revenue Variances

	Year Ended June 30,
	2011		2010		Increase (Decrease)
			(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 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.

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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	$	27,876		$	2.21		$	27,603		$	3.48		$	273
Workover and maintenance		33,095			2.62			19,630			2.47			13,465
Direct lease operating expense		178,507			14.12			95,379			12.01			83,128
Total lease operating expense		239,478			18.95			142,612			17.96			96,866
Production taxes		3,336			0.26			4,217			0.53			(881	)
Gathering and transportation		12,499			0.98			—			—			12,499
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
Interest income	$	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 $96.9 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. The gathering and transportation expense is essentially a direct result of the gathering and transportation systems acquired in the ExxonMobil Acquisition.

DD&A expense increased $111.8 million primarily due to a higher DD&A rate ($4.4 million) as a 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.

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

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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 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%. The decrease in the effective tax rate from fiscal year 2010 of 37% to 16% in 2011 was principally attributable to the release of the valuation allowance against the current tax on U.S. operating income.

Liquidity and Capital Resources

Overview

As of June 30, 2012, we had approximately $117.1 million in cash and cash equivalents on hand and approximately $1,018.3 million in outstanding total long-term debt obligations.

We have historically funded our operations primarily through cash flows from operations, borrowings under our revolving credit facility, and the issuance of debt and equity securities. Furthermore, we have historically used cash in the following ways:

• drilling and completing new natural gas and oil wells;

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

• constructing and installing new production infrastructure;

• acquiring additional reserves and producing properties;

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

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

• plugging and abandoning depleted or uneconomic wells; and

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

During the year ended June 30, 2012, we completed the following transactions that have improved our liquidity position, which are discussed in further detail below:

On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement which provided for increased flexibility to pay dividends or make loans from EGC to us and/or our other subsidiaries. The First Amendment includes the following provisions:

a) approval for cash distributions of up to $100 million per calendar year, which can be used for various purposes, including stock buybacks, bond repurchases, and /or debt repayments, and is based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds;

b) approval of a cash distribution basket of up to an aggregate of $150 million, to be used for investments and other purposes based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds; and

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c) increase of the amount of borrowing base availability that must be reserved to deal with potential effects from hurricanes during the period of July 1^st to October 31^st of each calendar year from $25 million to $50 million.

The First Amendment also provided that all distributions in aggregate from EGC to us and/or our subsidiaries are limited to an amount equal to $70 million plus 50% of our Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter.

On May 24, 2012, EGC entered into the Second Amendment (the “Second Amendment”) to the First Lien Credit agreement which provided further increased flexibility to make payments from EGC to us and/or our other subsidiaries. The Second Amendment includes the following provisions:

(a) removal of limitations on the ability of EGC to finance hedge option premiums;

(b) technical modifications in regard to the ability of EGC to reposition hedges;

(c) adjustment of definitions and other provisions to further increase the ability of EGC to make distributions to us and/or our subsidiaries; and

(d) technical corrections in connection with the replacement of one of the lenders (including that lender’s role as an issuer of a letter of credit) under the First Lien Credit Agreement.

At June 30, 2012, we had no borrowings under our First Lien Credit Agreement which had a borrowing base of $750 million due December 2014. The June 30, 2012 principal balance of our Senior Notes and related maturity dates were as follows:

• 9.25% Senior Notes — $750 million — Due December 2017; and

• 7.75% Senior Notes — $250 million — Due June 2019.

On April 2, 2012, the BOEM issued a letter stating that our Company qualifies for a supplemental bonding waiver. We still maintain approximately $24.5 million in bonds issued to third parties other than the BOEM to secure the plugging and abandonment of wells on the outer continental shelf of the Gulf of Mexico as well as the removal of platforms and related facilities.

Our initial fiscal 2013 capital budget, excluding any potential acquisition but including abandonment costs, is expected to be approximately $700 million ($670 million prior to plugging and abandonment costs). We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, from cash on hand, cash flows from operations and borrowings under our credit facility. We believe our available liquidity will be sufficient to meet our funding requirements through June 30, 2013. However, future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices. There can be no assurance that cash flow from operations or other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. Our capital expenditures and the scope of our drilling activities for fiscal year 2013 may change as a result of several factors, including, but not limited to, changes in natural gas and oil, costs of drilling and completion, drilling results and changes in the borrowing base under the First Lien Credit Agreement. If an acquisition opportunity arises, we may also seek to access public markets to issue additional debt and/or equity securities. Cash flows from operations were used primarily to fund exploration and development expenditures during fiscal 2012.

Cash Flows

The following table sets forth selected historical information from our statement of cash flows from operations:

	Year Ended June 30,
	2012			2011			2010
	(In thousands)
Net cash provided by operating activities	$	785,514		$	387,725		$	121,213
Net cash used in investing activities		(569,593	)		(1,255,072	)		(384,160	)
Net cash provided by (used in) financing activities		(127,241	)		881,530			188,246
Net increase (decrease) in cash and cash equivalents	$	88,680		$	14,183		$	(74,701	)

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Operating Activities

Net cash provided by operating activities during the year ended June 30, 2012 was $785.5 million as compared to $387.7 million provided by operating activities during fiscal 2011. The increase is due in part to higher net commodity prices and production volumes partially offset by higher production costs. Fiscal 2012 also included higher proceeds from monetization of derivative instruments and higher nonproduction costs and expenses. Changes in operating assets and liabilities increased $30.2 million primarily due to accounts receivable, asset retirement obligations and accounts payable and accrued liabilities.

Generally, producing natural gas and crude oil reservoirs have declining production rates. Production rates are impacted by numerous factors, including but not limited to, geological, geophysical and engineering matters, production curtailments and restrictions, weather, market demands and our ability to replace depleting reserves. Our inability to adequately replace reserves could result in a decline in production volumes, one of the key drivers of generating net operating cash flows. For the fiscal year ended June 30, 2012, our reserve replacement ratio, which is calculated by dividing acquisitions, discoveries, extensions of existing fields and revisions to proved reserves by total production, was 119%. Results for any year are a function of the success of our drilling program and acquisitions. While program results are difficult to predict, our current drilling inventory provides us opportunities to replace our production in fiscal year 2013.

Investing Activities

Our investments in properties, including acquisitions, were $577.1 million, $1,293.5 million and $438.1 million for the years ended June 30, 2012, 2011 and 2010, respectively. The decrease in cash used in investing activities in comparing fiscal 2012 to fiscal 2011 is primarily due to lower acquisitions in 2012 partially offset by higher investments in properties also in 2012.

Excluding any potential acquisitions but including abandonment costs, we currently anticipate an initial capital budget for 2013 of approximately $700 million. We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, from cash on hand, cash flows from our operations and borrowings under our credit facility. If an acquisition opportunity arises, we may also access public markets to issue additional debt and/or equity securities. As of July 31, 2012, we had $498 million availability for borrowing under our revolving credit facility. Our current borrowing base is $750 million. Our next borrowing base redetermination is scheduled for the fall of 2012 utilizing our June 30, 2012 reserve report. If commodity prices decline and banks lower their internal projections of natural gas and oil prices, it is possible that we will be subject to decreases in our borrowing base availability in the future. We anticipate that our cash flow from operations and available borrowing capacity under our revolving credit facility will exceed our planned capital expenditures and other cash requirements for the year ended June 30, 2013. However, future cash flows are subject to a number of variables, including the level of natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Cash used in financing activities was $127.2 million for the year ended June 30, 2012 as compared to cash provided by financing activities of $881.5 million for the year ended June 30, 2011. During the year ended June 30, 2012, total proceeds from issuance of common and preferred stock were $9.8 million and net repayments of our First Lien Credit Agreement were $111.6 million. During the year ended June 30, 2011, total proceeds from the issuance of common and preferred stock were $562.1 million and total proceeds from our 2011 senior notes offering and borrowings under our First Lien Credit Agreement net of repayments were $373.6 million.

Available Credit

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 through 2012 involving numerous countries and financial institutions impacted liquidity within the capital markets throughout the United States and around the world. 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 and stability to the financial sector, capital markets have

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remained somewhat constrained. As a result, we expect that our ability to raise debt and equity and the terms on which we can raise capital may be somewhat restricted and will be dependent upon the condition of the capital markets.

Notwithstanding periodic weakness in the U. S. credit markets, we expect that our available liquidity is sufficient to meet our operating and capital requirements through June 30, 2013. Additionally, our credit facility is comprised of a syndicate of large domestic and international banks, with no single lender providing more than 10% of the overall commitment amount.

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by our indirect, wholly-owned subsidiary, EGC in May 2011. This facility has a borrowing capacity of $925 million and matures December 31, 2014. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. At June 30, 2012, the borrowing base was $750 million, which was unanimously reaffirmed by the lenders on May 18, 2012. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.25% to 3.00% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves.

Under the First Lien Credit Agreement, EGC is prohibited from paying dividends to us except that EGC may make payments to us of up to $25 million in aggregate for the purpose of paying premiums or other payments associated with the early conversion of our preferred stock and EGC may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock. On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement which provided for increased flexibility to pay dividends or make loans from EGC to us and/or our other subsidiaries. The First Amendment modified the First Lien Credit Agreement and includes the following: (a) approval for cash distributions of up to $100 million per calendar year, which can be used for various purposes, including stock buybacks, bond repurchases, and /or debt repayments, and is based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds, and (b) approval of a cash distribution basket of up to an aggregate of $150 million, to be used for investments and other purposes based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds. Both distribution baskets are further limited by an amount equal to $70 million plus 50% of our Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter and (c) increased the amount of borrowing base availability that must be reserved to deal with potential effects from hurricanes during the period of July 1^st to October 31^st of each calendar year from $25 million to $50 million.

On May 24, 2012, EGC entered into the Second Amendment (the “Second Amendment”) to the First Lien Credit agreement which provided further increased flexibility to make payments from EGC to us and/or our other subsidiaries. The Second Amendment includes the following: (a) removal of limitations to the ability of EGC to finance hedge option premiums; (b) technical modifications in regard to the ability of EGC to reposition hedges; (c) adjustment of definitions and other provisions to further increase the ability of EGC to make distributions to us and/or our subsidiaries; and (d) technical corrections in connection with the replacement of one of the lenders (including that lender’s role as an issuer of a letter of credit) under the First Lien Credit Agreement.

The First Lien Credit Agreement (as amended) requires EGC to maintain certain financial covenants. Specifically, EGC may not permit the following: (a) EGC’s total leverage ratio to be more than 3.5 to 1.0, (b) EGC’s interest coverage ratio to be less than 3.0 to 1.0, and (c) EGC’s current ratio (in each case as defined in the First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to declare and pay dividends or other payments, our ability to incur debt, changes in control, our ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

As of June 30, 2012, we were in compliance with all covenants under our First Lien Credit Agreement.

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9.25% Senior Notes due 2017

On December 17, 2010, EGC issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). We exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act of 1933, as amended (the “Securities Act”), on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

The 9.25% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of June 30, 2012 was $802.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

7.75% Senior Notes due 2019

On February 25, 2011, EGC issued $250 million face value of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). We exchanged the full $250 million aggregate principal of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.

The 7.75% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of June 30, 2012 was $256.7 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

Potential Acquisitions

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

Contractual Obligations and Other Commitments

The table below provides estimates of the timing of future payments that, as of June 30, 2012, we are obligated to make under our contractual obligations and commitments, other than hedging contracts. We expect to fund these contractual obligations with cash on hand, cash generated from operations and borrowings available under our credit facility.

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	Payments Due by Period
	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
	(In Thousands)
Contractual Obligations
Total long-term debt(1)	$	1,018,344	$	4,284	$	14,060	$	—	$	1,000,000
Interest on long-term debt(1)		537,243		98,329		191,674		177,500		69,740
Operating leases(2)		12,695		2,451		4,534		4,266		1,444
Performance bonds(2)		25,132		25,132		—		—		—
Drilling rig commitments(2)		32,297		32,297		—		—		—
Letters of credit(2)		225,500		500		225,000		—		—
Total contractual obligations		1,851,211		162,993		435,268		181,766		1,071,184
Other Obligations
Asset retirement obligations(3)		301,415		34,457		21,603		11,109		234,246
Total obligations	$	2,152,626	$	197,450	$	456,871	$	192,875	$	1,305,430

(1) See Note 6 of Notes to Consolidated Financial Statements for details of our long-term debt.

(2) See Note 15 of Notes to Consolidated Financial Statements for discussion of these commitments.

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as defined by Item 303(a)(4)(ii) of Regulation S-K.

Critical Accounting Policies

We have identified the following policies as critical to the understanding of our results of operations. This is not a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the U.S. (“U.S. GAAP”), with no need for management’s judgment in selecting in their application. There are also areas in which management’s judgment in selecting any available alternative would not produce a materially different result. However, certain accounting policies are important to the portrayal of our consolidated financial condition and results of operations and require management’s most subjective or complex judgments. In applying those policies, management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. Our critical accounting policies and estimates are set forth below. Certain of these accounting policies and estimates are particularly sensitive because of their complexity and the possibility that future events affecting them may differ materially from our management’s current judgment. Our most sensitive accounting estimate affecting our consolidated financial statements is our oil and gas reserves, which are highly sensitive to changes in oil and gas prices that have been volatile in recent years. Although decreases in oil and gas prices are partially offset by our hedging program, to the extent reserves are adversely impacted by reductions in oil and gas prices, we could experience increased depreciation, depletion and amortization expense in future periods.

Use of Estimates  The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such difference may be material.

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Proved Oil and Gas Reserves  Proved oil and gas reserves are currently defined by the SEC as those volumes of oil and gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered from existing wells with existing equipment and operating methods. Although our internal and external engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires the engineers to make a number of assumptions based on professional judgment. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions in reserve quantities. Reserve revisions will inherently lead to adjustments of DD&A rates. We cannot predict the types of reserve revisions that will be required in future periods.

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

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

We evaluate the impairment of our evaluated oil and gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and gas properties are a significant factor in determining the full cost ceiling limitation of capital costs. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict. At June 30, 2012, 2011 and 2010, a 10% decrease in oil and gas prices would not impact the results of our full cost ceiling limitation test.

Asset Retirement Obligations.  Our investment in oil and gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that are difficult to predict.

Derivative Instruments.  We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Gains or losses resulting from transactions designated as hedges, recorded at market value, are deferred and recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of income as the physical production hedged by the contracts is delivered. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings.

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

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

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

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

The following table summarizes the sensitivity of our derivative contracts designated as hedges to changes in oil and gas prices. For the year ended June 30, 2012, the crude hedge contracts are separated into Brent and WTI indexed derivative contracts.

	June 30, 2012									June 30, 2011						June 30, 2010
	Oil (Bbl)						Gas (MMBtu)			Oil (Bbl)			Gas (MMBtu)			Oil (Bbl)			Gas (MMBtu)
	Brent			WTI
Average prices used in determining fair value	$	97.29		$	86.82		$	3.37		$	99.59		$	4.90		$	78.59		$	5.30
Decrease in fair value of derivative contracts resulting from a 10% increase in oil or natural gas prices (in thousands)(1)(2):	$	(28,943	)	$	(27,981	)	$	(1,510	)	$	(129,551	)	$	(9,530	)	$	(41,591	)	$	(11,905	)

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

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

Net income would have increased (decreased) for the years ended June 30, 2012, 2011 and 2010 by $126.1 million, $(96.2) million and $(13.0) million, respectively, if our crude oil and natural gas hedges did not qualify as cash flow hedges.

Income Taxes.  Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are

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capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate.

When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate any tax operating loss and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized in our consolidated financial statements. At June 30, 2012 we maintained an $82.3 million valuation allowance against our net deferred tax assets due in part to our three-year cumulative operating losses primarily as a result of the non-cash full cost ceiling impairment recorded in fiscal 2009. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors. If positive earnings trends continue or other events occur, the need for retaining this valuation allowance may diminish.

In light of our capital structure, U.S. withholding taxes attributable to interest due on loans from the Bermuda parent to the U.S. operating companies is provided as the interest accrues. This U.S. withholding tax (at 30%) is due when the interest is actually paid, and may not be offset or reduced by U.S. operating activity; although the interest expense is generally deductible in the U.S. when paid, subject to certain other limitations.

We follow the provisions of ASC Topic 740-10 (formally known as FIN 48, addressing “Uncertain Tax Positions”) and have not recorded any gross unrecognized tax benefits related to Uncertain Tax Positions.

Share-Based Compensation.  Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period.

Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-05: Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 provides that an entity that reports items of other comprehensive income has the option to present comprehensive income in either one continuous financial statement or two consecutive financial statements. The update is intended to increase the prominence of other comprehensive income in the financial statements. ASU 2011-05 is effective for annual periods beginning after December 15, 2011, with early adoption permitted. We adopted ASU 2011-05 on June 30, 2012 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

In December 2011, the FASB issued Accounting Standards Update No. 2011-12: Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (ASU 2011-12). The Update defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. As part of this update, the FASB did not defer the requirement to report comprehensive income either in a single continuous statement or in two separate but consecutive financial statements. ASU 2011-12 is effective for annual periods beginning after December 15, 2011.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

General

We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at June 30, 2012, and from which we may incur future gains or losses from changes in market interest rates or commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Hypothetical changes in commodity prices and interest rates chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Credit Risk

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries and to a lesser extent our derivative counterparties. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Although we have not generally required our counterparties to provide collateral to support their obligation to us, we may, if circumstances dictate, require collateral in the future. In this manner, we reduce credit risk.

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue.

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

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

For a complete discussion of our open commodity derivatives as of June 30, 2012, please see Note 9 to our Consolidated Financial Statements.

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As of June 30, 2012, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) in thousands):

	Crude Oil									Natural Gas
					Total									Total				Total
Period	Volume (MBbls)		Contract Price(1)		Asset (Liability)		Fair Value Gain (Loss)			Volume (MMBtu)		Contract Price(1)		Asset (Liability)		Fair Value Gain		Asset (Liability)		Fair Value Gain (Loss)(2)
Crude Oil – WTI Collars
7/12 – 12/12		1,417	$	72.60/$100.19	$	12	$	(404	)									$	12	$	(404	)
1/13 – 12/13		1,664		73.57/105.63		2,149		536											2,149		536
						2,161		132											2,161		132
Three-Way Collars
1/13 – 12/13		1,825		70/90/136.32		11,573		4,134											11,573		4,134
1/14 – 12/14		3,650		70/90/137.14		23,496		8,528											23,496		8,528
						35,069		12,662											35,069		12,662
Put Spreads
7/12 – 12/12		2,760		75.00/85.00		8,210		4,076											8,210		4,076
Swaps
7/12 – 12/12		92		86.60		40		(94 )											40		(94 )
1/13 – 12/13		183		86.60		(326 )		(188 )											(326 )		(188 )
7/12 – 12/12		(92 )		88.20		(187 )													(187 )
1/13 – 12/13		(183 )		88.20		37													37
						(436 )		(282 )											(436 )		(282 )
Crude Oil – Brent Collars
7/12 – 12/12		920		87.00/114.24		848		179											848		179
1/13 – 12/13		2,781		80.00/126.78		7,703		4,491											7,703		4,491
						8,551		4,670											8,551		4,670
Put Spreads
7/12 – 12/12		460		65.00/85.00		(127 )													(127 )
Call Spread
1/13 – 12/13											1,825	$	3.75/$4.75	$	460				460
Three-Way Collars
7/12 – 12/12		1,785		67.42/87.42/127.76		3,012		618			5,520		4.07/4.93/5.87		3,777		2,455		6,789		3,073
1/13 – 12/13		1,643		61.67/83.33/140.69		5,385		2,002			10,950		4.07/4.93/5.87		7,009		4,556		12,394		6,558
1/14 – 12/14		1,278		66.43/86.43/141.36		4,922		1,440											4,922		1,440
						13,319		4,060							10,786		7,011		24,105		11,071
Total Gain on Derivatives					$	66,747	$	25,318						$	11,246	$	7,011	$	77,993	$	32,329

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

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

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

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. Historically the basis differential between HLS and WTI has been relatively small and predictable. Over the past five years, HLS has averaged approximately $1 per barrel premium to WTI. Since the beginning of 2011, the HLS/WTI basis differential and volatility has increased with HLS carrying as much as a $30 per barrel premium to WTI. During the quarter ended September 30, 2011, the Company began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio as we believe that the Brent prices are more reflective of our

60

realized crude oil production pricing(HLS). By including Brent benchmarks in our crude hedging, we can more appropriately manage our exposure and our price risk.

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to our variable rate debt obligations. Specifically, we are exposed to changes in interest rates as a result of borrowings under our credit facility, and the terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. However, to reduce our future exposure to changes in interest rates, we may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues.

We generally invest cash equivalents in high-quality credit instruments consisting primarily of money market funds with maturities of 90 days or less. We do not expect any material loss from cash equivalents and therefore we believe its interest rate exposure on invested funds is not material. As of June 30, 2012 we had no borrowing under our First Lien Credit Agreement.

61

Item 8.  Financial Statements and Supplementary Data

	Page
Management’s Report on Internal Control over Financial Reporting		63
Reports of Independent Registered Public Accounting Firm		64
Consolidated Financial Statements
Consolidated Balance Sheets		66
Consolidated Statements of Income		67
Consolidated Statements of Comprehensive Income (Loss)		68
Consolidated Statements of Stockholders’ Equity		69
Consolidated Statements of Cash Flows		70
Notes to Consolidated Financial Statements		71

62

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed by management, under the supervision of our principal executive and principal financial officers, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the U.S. (GAAP) and includes those policies and procedures that:

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

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

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

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

Our management, under the supervision and participation of our principal executive officer and our principal financial officer, assessed the effectiveness of our internal control over financial reporting as of June 30, 2012. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on this assessment, our management has concluded that, as of June 30, 2012, our internal control over financial reporting was effective based on those criteria.

UHY LLP, the independent registered public accounting firm that audited the consolidated financial statements included in this Form 10-K, has issued a report on our internal control over financial reporting as of June 30, 2012. This report, dated August 9, 2012, appears on the following page.

63

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited Energy XXI (Bermuda) Limited and subsidiaries’ (the “Company”) internal control over financial reporting as of June 30, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, Energy XXI (Bermuda) Limited and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of June 30, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Energy XXI (Bermuda) Limited and subsidiaries as of June 30, 2012 and 2011, and the related consolidated statements of income, comprehensive income (loss), stockholders’ equity and cash flows for each of the three fiscal years in the period ended June 30, 2012, and our report dated August 9, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ UHY LLP

Houston, Texas
August 9, 2012

64

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Energy XXI (Bermuda) Limited (a Bermuda Corporation) and subsidiaries (the “Company”) as of June 30, 2012 and 2011, and the related consolidated statements of income, comprehensive income (loss), stockholders’ equity and cash flows for each of the three fiscal years in the period ended June 30, 2012. The Company’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Energy XXI (Bermuda) Limited and subsidiaries as of June 30, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three fiscal years in the period ended June 30, 2012, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Energy XXI (Bermuda) Limited and subsidiaries’ internal control over financial reporting as of June 30, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated August 9, 2012 expressed an unqualified opinion on the effective operation of internal control over financial reporting.

/s/ UHY LLP

Houston, Texas
August 9, 2012

65

ENERGY XXI (BERMUDA) LIMITED
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share information)

	June 30,
	2012			2011
ASSETS
Current Assets
Cash and cash equivalents	$	117,087		$	28,407
Accounts receivable
Oil and natural gas sales		126,107			126,194
Joint interest billings		3,840			4,526
Insurance and other		5,420			2,533
Prepaid expenses and other current assets		63,029			47,751
Derivative financial instruments		32,497			22
Total Current Assets		347,980			209,433
Property and Equipment
Oil and natural gas properties – full cost method of accounting, including $418.8 million and $467.3 million of unevaluated properties not being amortized at June 30, 2012 and 2011, respectively		2,698,213			2,545,336
Other property and equipment		9,533			8,201
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		2,707,746			2,553,537
Other Assets
Derivative financial instruments		45,496			—
Deferred income taxes		—			2,411
Debt issuance costs, net of accumulated amortization and other assets		29,725			33,479
Total Other Assets		75,221			35,890
Total Assets	$	3,130,947		$	2,798,860
LIABILITIES
Current Liabilities
Accounts payable		156,959		$	163,741
Accrued liabilities		118,818			111,157
Notes payable		22,211			19,853
Asset retirement obligations		34,457			19,624
Derivative financial instruments		—			50,259
Current maturities of long-term debt		4,284			4,054
Total Current Liabilities		336,729			368,688
Long-term debt, less current maturities		1,014,060			1,109,333
Deferred income taxes		104,280			—
Asset retirement obligations		266,958			303,618
Derivative financial instruments		—			70,524
Other liabilities		3,080			—
Total Liabilities		1,725,107			1,852,163
Commitments and Contingencies (Note 15)
Stockholders’ Equity
Preferred stock, $0.001 par value, 7,500,000 and 2,500,000 shares authorized at June 30, 2012 and 2011, respectively
7.25% Convertible perpetual preferred stock, 8,000 shares issued and outstanding at June 30, 2012 and 2011, respectively		—			—
5.625% Convertible perpetual preferred stock, 814,117 and 1,050,000 shares issued and outstanding at June 30, 2012 and 2011, respectively		1			1
Common stock, $0.005 par value, 200,000,000 shares authorized and 79,147,340 and 76,203,574 shares issued and 78,837,697 and 76,202,921 shares outstanding at June 30, 2012 and 2011, respectively		396			381
Additional paid-in capital		1,501,785			1,479,959
Accumulated deficit		(153,945	)		(465,160	)
Accumulated other comprehensive income (loss), net of income taxes		57,603			(68,484	)
Total Stockholders’ Equity		1,405,840			946,697
Total Liabilities and Stockholders’ Equity	$	3,130,947		$	2,798,860

 
 
See accompanying Notes to Consolidated Financial Statements

66

ENERGY XXI (BERMUDA) LIMITED
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, except per share information)

	Year Ended June 30,
	2012			2011			2010
Revenues
Crude oil sales	$	1,186,631		$	719,683		$	387,935
Natural gas sales		116,772			139,687			110,996
Total Revenues		1,303,403			859,370			498,931
Costs and Expenses
Lease operating		310,815			239,478			142,612
Production taxes		7,261			3,336			4,217
Gathering and transportation		16,371			12,499			—
Depreciation, depletion and amortization		367,463			293,479			181,640
Accretion of asset retirement obligations		39,161			32,127			23,487
General and administrative expense		86,276			75,091			49,667
(Gain) loss on derivative financial instruments		(7,228	)		(5,563	)		(4,739	)
Total Costs and Expenses		820,119			650,447			396,884
Operating Income		483,284			208,923			102,047
Other Income (Expense)
Bridge loan commitment fees		—			(4,500	)		—
Loss on retirement of debt		—			(21,855	)		—
Other income – net		71			198			29,756
Interest expense		(108,882	)		(105,849	)		(88,239	)
Total Other Expense		(108,811	)		(132,006	)		(58,483	)
Income Before Income Taxes		374,473			76,917			43,564
Income Tax Expense		38,646			12,262			16,244
Net Income		335,827			64,655			27,320
Induced Conversion of Preferred Stock		6,068			24,348			—
Preferred Stock Dividends		13,028			12,600			4,320
Net Income Available for Common Stockholders	$	316,731		$	27,707		$	23,000
Earnings per Share
Basic	$	4.10		$	0.42		$	0.56
Diluted	$	3.85		$	0.42		$	0.56
Weighted Average Number of Common Shares Outstanding
Basic		77,310			66,356			40,992
Diluted		87,208			66,459			41,384

 
 
See accompanying Notes to Consolidated Financial Statements

67

ENERGY XXI (BERMUDA) LIMITED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	Year Ended June 30,
	2012			2011			2010
Net Income	$	335,827		$	64,655		$	27,320
Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		228,398			(136,566	)		35,320
Effective portion reclassified to earnings during the period		(34,418	)		(11,418	)		(48,448	)
Interest Rate Cash Flow Hedges
Reclassified to earnings during the period		—			—			(3,474	)
Total Other Comprehensive Income (Loss)		193,980			(147,984	)		(16,602	)
Income taxes		67,893			(51,794	)		(5,811	)
Net Other Comprehensive Income (Loss)		126,087			(96,190	)		(10,791	)
Comprehensive Income (Loss)	$	461,914		$	(31,535	)	$	16,529

 
 
See accompanying Notes to Consolidated Financial Statements

68

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

	Preferred Stock															Additional Paid-in Capital			Accumulated Deficit			Other Comprehensive Income (Loss)			Total Stock- holders’ Equity
	5.625%					7.25%						Common Stock
	Shares			Value		Shares			Value			Shares		Value
Balance, June 30, 2009													29,283	$	146	$	604,724		$	(515,867	)	$	38,497		$	127,500
Common stock issued, net of direct costs													21,466		108		186,714									186,822
Stock-based compensation													70				3,480									3,480
Preferred stock issued, net of direct costs							1,100		$	11							106,539									106,550
Preferred stock dividends																				(4,320	)					(4,320	)
Comprehensive income (loss)																				27,320			(10,791	)		16,529
Balance, June 30, 2010							1,100			11			50,819		254		901,457			(492,867	)		27,706			436,561
Common stock issued, net of direct costs													14,068		71		283,322									283,393
Stock-based compensation													280		1		4,442									4,443
Preferred stock issued, net of direct costs		1,150		$	1												278,391									278,392
Preferred stock converted to common		(100	)				(1,092	)		(11	)		10,562		53		(42	)								—
Preferred stock dividends																				(12,600	)					(12,600	)
Preferred stock inducement													475		2		12,389			(24,348	)					(11,957	)
Comprehensive income (loss)																				64,655			(96,190	)		(31,535	)
Balance, June 30, 2011		1,050			1		8			—			76,204		381		1,479,959			(465,160	)		(68,484	)		946,697
Common stock issued, net of direct costs													257		1		10,051									10,052
Stock-based compensation													367		2		11,758									11,760
Preferred stock converted to common		(236	)		—								2,319		12		(12	)								—
Common stock dividends																				(5,516	)					(5,516	)
Preferred stock dividends																				(13,028	)					(13,028	)
Preferred stock inducement																	29			(6,068	)					(6,039	)
Comprehensive income																				335,827			126,087			461,914
Balance, June 30, 2012		814		$	1		8		$	—			79,147	$	396	$	1,501,785		$	(153,945	)	$	57,603		$	1,405,840

 
 
See accompanying Notes to Consolidated Financial Statements

69

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

	Year Ended June 30,
	2012			2011			2010
Cash Flows From Operating Activities
Net income	$	335,827		$	64,655		$	27,320
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		367,463			293,479			181,640
Deferred income tax expense		38,796			12,169			16,238
Change in derivative financial instruments
Proceeds from sale of derivative instruments		66,522			42,577			5,000
Other – net		(52,155	)		(37,047	)		(35,633	)
Accretion of asset retirement obligations		39,161			32,127			23,487
Amortization of debt discount and premium		—			(43,521	)		(36,364	)
Amortization and write-off of debt issuance costs and other		7,559			15,772			7,806
Stock-based compensation		11,760			4,443			3,480
Payment of interest in-kind		—			2,225			4,009
Changes in operating assets and liabilities
Accounts receivable		(4,995	)		(49,745	)		(18,398	)
Prepaid expenses and other current assets		(15,890	)		(13,272	)		(16,415	)
Settlement of asset retirement obligations		(14,990	)		(73,974	)		(80,044	)
Accounts payable and accrued liabilities		6,456			137,837			39,087
Net Cash Provided by Operating Activities		785,514			387,725			121,213
Cash Flows from Investing Activities
Acquisitions		(6,401	)		(1,012,262	)		(293,037	)
Capital expenditures		(570,670	)		(281,233	)		(145,112	)
Insurance payments received		6,472			—			53,985
Proceeds from the sale of properties		2,750			38,431			—
Other		(1,744	)		(8	)		4
Net Cash Used in Investing Activities		(569,593	)		(1,255,072	)		(384,160	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		9,839			562,112			294,468
Conversion of preferred stock to common stock		(6,040	)		(11,957	)		—
Dividends to shareholders		(18,682	)		(12,313	)		(3,988	)
Proceeds from long-term debt		896,717			1,829,828			205,903
Payments on long-term debt		(1,008,300	)		(1,456,190	)		(294,013	)
Debt issuance costs		—			(29,614	)		(13,030	)
Other		(775	)		(336	)		(1,094	)
Net Cash Provided by (Used in) Financing Activities		(127,241	)		881,530			188,246
Net Increase (Decrease) in Cash and Cash Equivalents		88,680			14,183			(74,701	)
Cash and Cash Equivalents, beginning of year		28,407			14,224			88,925
Cash and Cash Equivalents, end of year	$	117,087		$	28,407		$	14,224

 
 
See accompanying Notes to Consolidated Financial Statements

70

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies

Nature of Operations.  Energy XXI (Bermuda) Limited was incorporated in Bermuda on July 25, 2005. We are headquartered in Houston, Texas. We are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico.

References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

Principles of Consolidation and Reporting.  The accompanying consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported consolidated net income, consolidated stockholders’ equity or consolidated cash flows.

Use of Estimates.  The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such difference may be material.

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

Accounts Receivable and Allowance for Doubtful Accounts.  Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2012 and 2011, no allowance for doubtful accounts was necessary.

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

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

71

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Depreciation, Depletion and Amortization.  The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method. Other property, which includes, leasehold improvements, office and computer equipment and vehicles are stated at original cost and are depreciated using the straight-line method over the useful life of the assets, which ranges from three to five years.

Weather Based Insurance Linked Securities.  We obtain Weather Based Insurance Linked Securities (“Securities”), to mitigate potential loss to our oil and gas properties from hurricanes in the Gulf of Mexico. These Securities provide for payments of negotiated amounts should a pre-defined category hurricane pass within specific pre-defined areas encompassing our oil and gas producing fields. Since these Securities were obtained to mitigate potential loss due to hurricanes in the Gulf of Mexico, the majority of the premiums associated with these Securities are charged to expense during the period associated with the hurricane season, typically June 1 to November 30. The amortization of insurance premiums for these Securities is recorded as a component of our lease operating expense. Unamortized premiums of $3.2 million are included in prepaid expenses at June 30, 2012.

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

Derivative Instruments.  We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Gains or losses resulting from transactions designated as cash flow hedges are recorded at market value and are recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of income as the physical production hedged by the contracts is delivered. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings.

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

Debt Issuance Costs.  Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the scheduled maturity of the debt utilizing the straight-line method, which approximates the interest method.

Asset Retirement Obligations.  Our investment in oil and gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value

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ENERGY XXI (BERMUDA) LIMITED
  
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Note 1 — Organization and Summary of Significant Accounting Policies  – (continued)

of the future costs are added to the capitalized cost of our oil and gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

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

General and Administrative Expense.  Under the full cost method of accounting, a portion of our general and administrative expense that is directly identified with our acquisition, exploration and development activities is capitalized as part of oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to directly support those employees that are directly involved in acquisition, exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities. Our capitalized general and administrative expense directly related to our acquisition, exploration and development activities for the years ended June 30, 2012, 2011 and 2010 was $38.3 million, $37.8 million and $26.6 million, respectively.

Share-Based Compensation.  Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period.

Income Taxes.  Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate.

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

We follow the provisions of ASC Topic 740-10 (formally known as FIN 48, addressing “Uncertain Tax Positions”) and have not recorded any gross unrecognized tax benefits related to Uncertain Tax Positions.

In light of our capital structure, U.S. withholding taxes attributable to interest due on loans from the Bermuda parent to the U.S. operating companies is provided as the interest accrues. This U.S. withholding tax (at 30%) is due when the interest is actually paid, and may not be offset or reduced by U.S. operating activity; although the interest expense is generally deductible in the U.S. when paid, subject to certain other limitations.

Earnings per Share.  The Earnings per Share (“EPS”) amounts have been calculated based on the weighted-average number of shares of common stock outstanding for the year. Diluted EPS reflects the potential dilution, using the treasury stock method. The diluted EPS calculation includes shares of common stock from the assumed conversion of the Company’s redeemable preferred stock.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 — Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-05: Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 provides that an entity that reports items of other comprehensive income has the option to present comprehensive income in either one continuous financial statement or two consecutive financial statements. The update is intended to increase the prominence of other comprehensive income in the financial statements. ASU 2011-05 is effective for annual periods beginning after December 15, 2011, with early adoption permitted. We adopted ASU 2011-05 on June 30, 2012 and the adoption had no effect on our consolidated financial position, results of operations or cash flows other than presentation.

In December 2011, the FASB issued Accounting Standards Update No. 2011-12: Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (ASU 2011-12). The Update defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. As part of this update, the FASB did not defer the requirement to report comprehensive income either in a single continuous statement or in two separate but consecutive financial statements. ASU 2011-12 is effective for annual periods beginning after December 15, 2011.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

Note 3 — Acquisitions and Dispositions

ExxonMobil Acquisition

On December 17, 2010, we closed on the acquisition of certain shallow-water Gulf of Mexico shelf oil and natural gas interests (the “ExxonMobil Properties”) from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”). The ExxonMobil Acquisition was funded through a combination of cash on hand, including proceeds from common and preferred equity offerings (see “Note 10 — Stockholders’ Equity”), borrowings under our revolving credit facility and proceeds from the $750 million private placement by our indirect, wholly owned operating subsidiary, Energy XXI Gulf Coast, Inc. (“EGC”), of 9.25% Senior Notes.

Revenues and expenses related to the ExxonMobil Properties from the closing date (December 17, 2010) to June 30, 2011 are included in the June 30, 2011 results of operations.

Pursuant to the Purchase and Sale Agreement (the “PSA”), ExxonMobil reserved a 5% overriding royalty interest in the ExxonMobil Properties for production from depths below approximately 16,000 feet. In addition, the PSA required us to post a $225 million letter of credit, which we posted under our revolving credit facility, in favor of ExxonMobil to guarantee our obligation to plug and abandon the ExxonMobil Properties in the future.

The ExxonMobil Acquisition was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

As of December 31, 2011, the Company’s measurement period adjustments were complete. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 17, 2010 (in thousands):

	December 17, 2010 (As initially reported)			Measurement period adjustment		December 17, 2010 (As adjusted)
Oil and natural gas properties – evaluated	$	926,422		$	—	$	926,422
Oil and natural gas properties – unevaluated		289,711			—		289,711
Net working capital*		101			577		678
Asset retirement obligations		(204,512	)		—		(204,512	)
Cash paid	$	1,011,722		$	577	$	1,012,299

* Net working capital includes gas imbalance receivables and payables and ad valorem taxes payable.

The fair values of evaluated and unevaluated oil and gas properties and asset retirement obligation liabilities were measured using valuation techniques that convert future cash flows to a single discounted amount. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

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. For accounting purposes, we recorded the Mit Acquisition as effective November 20, 2009, the date that we gained control of the assets acquired and liabilities assumed. We financed the Mit Acquisition through proceeds received from common and perpetual preferred stock offerings (See Note 10).

The Mit Acquisition was accounted for under the purchase method of accounting. Accordingly, we conducted an assessment of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. Transaction, transition and integration costs associated with this acquisition were expensed as incurred.

The Mit Acquisition involved similar non-operated interests in the same group of properties we purchased from Pogo Producing Company in June 2007. These properties include 30 fields of which production is approximately 77% crude oil and 80% of which we presently operate. Offshore leases included in this acquisition total nearly 33,000 net acres.

The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 20, 2009 (in thousands):

Oil and natural gas properties – evaluated	$	292,609
Oil and natural gas properties – unevaluated		41,987
Net working capital		4,237
Asset retirement obligations		(62,604	)
Cash paid	$	276,229

Net working capital includes gas imbalance receivables and payables and ad valorem taxes payable.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

The fair values of evaluated and unevaluated oil and gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

Sale of Certain Onshore Properties

In June 2011, we closed on the sale of certain onshore oil and natural gas properties for cash consideration of $39.6 million. Revenues and expenses related to the sold properties have been included in our results of operations through the closing dates. The proceeds were recorded as a reduction to our oil and gas properties with no gain or loss being recognized.

Below is a summary of net reduction to the full cost pool related to the sale (in thousands):

Cash received	$	39,625
Reduction of asset retirement obligation related to properties		16,626
Net revenues from June 1, 2011 through closing date		(1,630	)
Adjustment to gas imbalances related to properties		36
Net reduction to the full cost pool	$	54,657

Note 4 — Property and Equipment

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

	June 30,
	2012		2011
Oil and gas properties
Proved properties	$	4,375,984	$	3,810,293
Less: accumulated depreciation, depletion, amortization and impairment		2,096,531		1,732,250
Proved properties		2,279,453		2,078,043
Unproved properties		418,760		467,293
Oil and gas properties		2,698,213		2,545,336
Other property and equipment		22,132		18,354
Less: accumulated depreciation		12,599		10,153
Other property and equipment		9,533		8,201
Total property and equipment – net of accumulated depreciation, depletion, amortization and impairment	$	2,707,746	$	2,553,537

Note 5 — Equity Method Investments

Investments accounted for under the equity method consist of our 20% interest in Energy XXI Natural Gas Partners, LLC (“EXXI NGP”), which engages in the acquisition, exploration, development and operation of oil and natural gas properties in Louisiana and Texas and offshore in the Gulf of Mexico, through its wholly owned subsidiary Natural Gas Partners Assets, LLC (“NGP”). Our equity method investment is included in other assets in the consolidated balance sheets and our share of earnings is reported in other income (expense) in the consolidated statements of income.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Equity Method Investments  – (continued)

On June 4, 2012, NGP entered into a Purchase and Sale Agreement (“PSA Agreement”) with EP Energy E&P Company, L.P. (“EP Energy”) to acquire interests in certain oil and gas fields owned by EP Energy. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was $103 million. Pursuant to the PSA Agreement, we paid our share of the deposit of $2.1 million. The effective date of the acquisition is January 1, 2012.

On July 19, 2012, NGP closed on the acquisition and we paid our share of the remaining purchase price of $16 million to EP Energy, prior to final adjustments. EXXI NGP is a guarantor of $100 million line of credit entered into by NGP. There was no borrowing base under this facility as of June 30, 2012 and was set at $25 million upon closing on July 19, 2012. For the period ended June 30, 2012, our share of loss in NGP was approximately $0.1 million, representing formation expenses and other related costs. At June 30, 2012, the carrying value of our investment in EXXI NGP was $2.1 million.

Note 6 — Long-Term Debt

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

	June 30,
	2012		2011
Revolving credit facility	$	—	$	107,784
9.25% Senior Notes due 2017		750,000		750,000
7.75% Senior Notes due 2019		250,000		250,000
Derivative instruments premium financing		17,387		4,926
Capital lease obligation		957		677
Total debt		1,018,344		1,113,387
Less current maturities		4,284		4,054
Total long-term debt	$	1,014,060	$	1,109,333

Maturities of long-term debt as of June 30, 2012 are as follows (in thousands):

Year Ending June 30,
2013	$	4,284
2014		8,242
2015		5,818
2016		—
2017		—
Thereafter		1,000,000
Total	$	1,018,344

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by our indirect, wholly-owned subsidiary, EGC, in May 2011. This facility has a borrowing capacity of $925 million and matures December 31, 2014. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. At June 30, 2012, the borrowing base was $750 million, which was reaffirmed by the lenders on May 18, 2012. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.25% to 3.00% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

Under the First Lien Credit Agreement, EGC is prohibited from paying dividends to us except that EGC may make payments to us of up to $25 million in aggregate for the purpose of paying premiums or other payments associated with the early conversion of our preferred stock and EGC may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock. On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement. The First Amendment modified the First Lien Credit Agreement and includes the following: (a) approval for cash distributions of up to $100 million per calendar year, which can be used for various purposes, including stock buybacks, bond repurchases, and/or debt repayments, and is based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds, (b) approval of a cash distribution basket of up to an aggregate of $150 million, to be used for investments and other purposes based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds. Both distribution baskets are further limited by an amount equal to $70 million plus 50% of our Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter and (c) increased the amount of borrowing base availability that must be reserved to deal with potential effects from hurricanes during the period of July 1^st to October 31^st of each calendar year from $25 million to $50 million.

On May 24, 2012, EGC entered into the Second Amendment (the “Second Amendment”) to the First Lien Credit agreement which provided further increased flexibility to make payments from EGC to us and/or our other subsidiaries. The Second Amendment includes the following: (a) removal of limitations on the ability of EGC to finance hedge option premiums; and (b) technical modifications in regard to the ability of EGC to reposition hedges; (c) adjustment of definitions and other provisions to further increase the ability of EGC to make distributions to us and/or our subsidiaries; and (d) technical corrections in connection with the replacement of one of the lenders (including that lender’s role as an issuer of a letter of credit) under the First Lien Credit Agreement.

The First Lien Credit Agreement (as amended) requires EGC to maintain certain financial covenants. Specifically, EGC may not permit the following under First Lien Credit Agreement: (a) EGC’s total leverage ratio to be more than 3.5 to 1.0, (b) EGC’s interest coverage ratio to be less than 3.0 to 1.0, and (c) EGC’s current ratio (in each case as defined in our First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to declare and pay dividends or other payments, our ability to incur debt, changes in control, our ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

As of June 30, 2012, we were in compliance with all covenants under our First Lien Credit Agreement.

High Yield Facilities

9.25% Senior Notes

On December 17, 2010, EGC issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). We exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act of 1933, as amended (the “Securities Act”), on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

any equity raised. We incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

We have the right to redeem the 9.25% Senior Notes under various circumstances and are required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of June 30, 2012 was $802.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

Guarantee of 9.25% Notes Issued by EGC

Our indirect, wholly-owned subsidiary, EGC, is the issuer of the 9.25% Notes which are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We and our subsidiaries, other than EGC, have no significant independent assets or operations. EGC is prohibited from paying dividends to us except that EGC may make payments to us of up to $25 million in aggregate for the purpose of paying premiums or other payments associated with the early conversion of our preferred stock and EGC may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock.

7.75% Senior Notes

On February 25, 2011, EGC issued $250 million face value of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). We exchanged the full $250 million aggregate principal of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised. We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

We have the right to redeem the 7.75% Senior Notes under various circumstances and are required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of June 30, 2012 was $256.7 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

Guarantee of 7.75% Notes Issued by EGC

Our indirect, wholly-owned subsidiary, EGC, is the issuer of the 7.75% Notes which are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We and our subsidiaries, other than EGC, have no significant independent assets or operations. EGC is prohibited from paying dividends to us except that EGC may make payments to us of up to $25 million in aggregate for the purpose of paying premiums or other payments associated with the early conversion of our preferred stock and EGC may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

10% Senior Notes

On June 8, 2007, we completed a private offering of $750 million aggregate principal amount of EGC’s 10% Senior Notes due 2013 (the “Old 10% Notes”). On October 16, 2007, we exchanged all of the then issued and outstanding Old 10% Notes for $750 million aggregate principal amount of newly issued 10% Senior Notes due 2013 (the “New Senior Notes”) which had been registered under the Securities Act of 1933, as amended (the “Securities Act”), and contained substantially the same terms as the Old 10% Notes. We did not receive any cash proceeds from the exchange of the Old 10% Notes for the New Senior Notes.

We previously purchased a total of $126.0 million aggregate principal amount of the New 10% Notes at a cost of $90.9 million, plus accrued interest of $3.3 million for a total cost of $94.2 million, reflecting a total gain of $35.1 million pre-tax. As discussed below, on November 12, 2009, we issued $278 million aggregate principal amount of 16% Second Lien Junior Secured Notes due 2014 (“Second Lien Notes”), in exchange for $347.5 million aggregate principal amount of New 10% Notes. In conjunction with the exchange, we contributed $126 million face value of New 10% Notes which we had previously purchased to EGC, who subsequently retired them.

On December 17, 2010, we called $47.6 million face value of the New 10% at 105% of par plus accrued interest. This transaction closed on January 18, 2011. The $2.38 million difference between the call price and the $47.6 million carrying value of the 10% Second Lien notes was charged to loss on retirement of the New 10% notes in the March 31, 2011 quarter.

On February 10, 2011, we offered to purchase for cash (the “Tender Offer”), any and all remaining outstanding New 10% Notes at $1,050 per $1,000 principal amount of New 10% Notes (if tendered on or before February 24, 2011) or at $1,020 per $1,000 principal amount of New 10% Notes if tendered after February 24, 2011 but on or before March 10, 2011. A total of $122.3 million face amount of New 10% Notes were tendered by the February 24, 2011 date and an additional $311,130 face value of New 10% Notes were tendered subsequent to February 24, 2011 but on or before March 10, 2011.

On April 18, 2011, we called the remaining $106.3 million of our New 10% Notes at a call price of 102.5% of par. The redemption closed on June 15, 2011 with full participation.

16% Second Lien Notes

On November 12, 2009, we issued Second Lien Notes as follows:

• A total of $278 million of Second Lien Notes were issued in exchange for $347.5 million of New Senior Notes; and

• A total of $60 million of Second Lien Notes were issued for cash (for each $1.0 million in Second Lien Notes purchased for cash, the purchaser also received 44,082 shares of our common stock).

The Second Lien Notes had a maturity date of June 2014 and were secured by a second lien in our oil and gas properties. In addition, the Second Lien Notes were governed by an inter-creditor agreement between the participants in the revolving credit facility and the Second Lien Notes. Cash interest payable on the Second Lien Notes is 14% with an additional 2% interest payable-in-kind (“Second Lien Note PIK interest”). The Second Lien Note PIK interest was paid through the issuance of additional Second Lien Notes on each interest payment date, with identical terms and conditions to the original Second Lien Notes.

Under the terms of the Second Lien Notes, we were required to exchange the Second Lien Notes for newly issued notes registered under the Securities Act (the “Registered Second Lien Notes”). The Registered Second Lien Notes had identical terms and conditions as the Second Lien Notes. On April 5, 2010, we commenced an offer to exchange the Second Lien Notes for Registered Second Lien Notes. The exchange offer expired on May 3, 2010 and closing was on May 6, 2010. The tendered bonds represented 99.96% of the bonds outstanding.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

For accounting purposes, the $278 million aggregate principal amount of Second Lien Notes exchanged for $347.5 million aggregate principal amount of New Senior Notes were recorded at the carrying value of the Registered Second Lien Notes ($347.5 million) and the $69.5 million difference between face value of the Second Lien Notes and carrying value of the New Senior Notes was amortized as a reduction of interest expense over the life of the New Senior Notes.

For accounting purposes, the $60 million aggregate principal amount of Second Lien Notes for which we received cash were recorded based on the relative fair market values of the Second Lien Notes and the 2.6 million shares of common stock issued using closing price of $10.60 per share of our common stock on November 12, 2009. Based on these relative fair market values, the $60 million aggregate principal amount of Second Lien Notes was recorded at $40.9 million and the common shares were recorded at $19.1 million. The $19.1 million discount between the face value of the $60 million aggregate principal amount of Second Lien Notes and their recorded value was amortized as an increase in interest expense over the life of the Registered Second Lien Notes.

Refinancing of Existing 16% Second Lien Notes

On November 9, 2010, we called for redemption of $119.7 million aggregate principal amount of our 16% Second Lien Notes at a redemption price of 110% of the principal amount, plus accrued and unpaid interest, pursuant to the terms of the indenture governing the 16% Second Lien Notes. This redemption closed on December 9, 2010. The total payment of $140.9 million included $9.3 million of accrued interest and $12.0 million in redemption premium.

On November 29, 2010, we commenced a tender offer for the $222.3 million principal amount of our remaining outstanding 16% Second Lien Notes. In December 2010, a total of $219.9 million face value of 16% Second Lien Notes were tendered. The total payment of $251.0 million included $171,513 of accrued interest and $31.0 million in redemption premium.

On December 17, 2010, we commenced a call of the remaining outstanding 16% Second Lien Notes which closed on January 18, 2011. In December 2010, we escrowed $5.4 million in funds with the trustee of the 16% Second Lien Notes, which were sufficient to redeem the remaining outstanding notes.

A total of $42.9 million in redemption premiums were paid related to the call and tender of the 16% Second Lien Notes at December 31, 2010.

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value net of derivative instrument premium financing. As of June 30, 2012 and June 30, 2011, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $17.4 million and $4.9 million, respectively.

81

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

Interest Expense

For the years ended June 30, 2012, 2011 and 2010, interest expense consisted of the following (in thousands):

	Year Ended June 30,
	2012		2011			2010
Revolving credit facility	$	9,420	$	10,080		$	9,954
9.25% Senior Notes due 2017		69,375		37,193			—
7.75% Senior Notes due 2019		19,375		6,727			—
10% Senior Notes due 2013		—		20,811			40,442
16% Second Lien Notes due 2014		—		24,967			34,330
Amortization of debt issue cost – Revolving credit facility		4,881		6,999			3,015
Amortization of debt issue cost – 10% Senior Notes due 2013		—		1,681			2,522
Amortization of debt issue cost – 16% Second Lien Notes due 2014		—		54			72
Amortization of debt issue cost – 9.25% Senior Notes due 2017		2,206		1,196			—
Amortization of debt issue cost – 7.25% Senior Notes due 2019		388		141			—
Discount amortization – 16% Second Lien Notes due 2014 (Private Placement)		—		1,894			2,605
Premium amortization – 16% Second Lien Notes due 2014 (Exchange Offer)		—		(6,889	)		(9,477	)
Write-off of debt issue costs – Related to retirement of new 10 % notes		—		—			1,750
Write-off of debt issue costs – Reduction in revolving credit facility		—		—			447
Derivative instruments premium financing and other		1,347		995			2,579
Settlement of Lehman Brothers liability		1,890		—			—
	$	108,882	$	105,849		$	88,239

Bridge Loan Commitment Fee

In November 2010, we entered into a Bridge Facility Commitment Letter (the “Bridge Commitment”) with a group of banks to provide a $450 million Bridge Facility, if needed, to acquire the ExxonMobil Properties. The Bridge Commitment required the payment of a commitment fee in the amount of 1% of the full amount of the commitments in respect to the Bridge Facility as well as certain other fees in the event we utilized the Bridge Facility to finance the ExxonMobil Acquisition. We did not utilize the Bridge Facility and paid the banks the $4.5 million commitment fee, which is included in Other Income (Expense).

Note 7 — Notes Payable

In May 2011, we entered into a note with Bank Direct Capital Finance, LLC to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bore interest at an annual rate of 1.93%. The note amortized over ten months. The balance outstanding as of June 30, 2011 was $19.9 million.

In July 2011, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $6.3 million and bore interest at an annual rate of 1.93%. The note amortized over the remaining term of the insurance and matured on May 1, 2012.

In May 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $26.0 million and bore interest at an annual rate of 1.556%. The note amortizes over the remaining term of the insurance, which matures on December 26, 2012. The balance outstanding as of June 30, 2012 was $22.2 million.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 — Asset Retirement Obligations

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

	Year Ended June 30,
	2012			2011
Balance at beginning of year	$	323,242		$	159,277
Liabilities acquired		125			204,512
Liabilities incurred		2,268			18,086
Liabilities settled		(14,990	)		(73,974	)
Liabilities sold		—			(16,626	)
Revisions in estimated cash flows		(48,391	)		(160	)
Accretion expense		39,161			32,127
Total balance at end of year		301,415			323,242
Less current portion		34,457			19,624
Long-term balance at end of year	$	266,958		$	303,618

Note 9 — Derivative Financial Instruments

We enter into hedging transactions with a diversified group of investment-grade rated counterparties, primarily financial institutions for our derivative transactions to reduce the concentration of exposure to any individual counterparty and to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. The Company designates a majority of its derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled.

When the Company discontinues cash flow hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, changes to fair value accumulated in other comprehensive income are recognized immediately into earnings.

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

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. Historically the basis differential between HLS and WTI has been relatively small and predictable. Over the past five years, HLS has averaged approximately $1 per barrel premium to WTI. Since the beginning of 2011, the HLS/WTI basis differential and volatility has increased with HLS carrying as much as a $30 per barrel premium to WTI. During the

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

quarter ended September 30, 2011, the Company began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By including Brent benchmarks in our crude hedging, we can more appropriately manage our exposure and price risk.

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

We have monetized certain hedge positions and received the following cash proceeds in the following quarters (in thousands):

Quarter Ended	Cash Proceeds
March 31, 2009	$	66,500
March 31, 2010		5,000
September 30, 2010		34,100
December 31, 2010		8,500
September 30, 2011		49,600
December 31, 2011		16,800
March 31, 2012		2,012
	$	182,512

These above monetized amounts were recorded in stockholders’ equity as part of other comprehensive income and are recognized in income over the contract life of the underlying hedge contracts. An additional $0.8 million monetization was captured in the September 30, 2011 quarter with the cash to be received when the underlying hedge contract settles during calendar 2013.

Our future crude oil and natural gas revenue will be increased by the following amounts related to the monetized contracts referred to above (in thousands):

Quarter Ended	Cash(1)		Non-Cash(1)		Total
September 30, 2012	$	9,537	$	—	$	9,537
December 31, 2012		9,046		—		9,046
March 31, 2013		4,821		203		5,024
June 30, 2013		4,858		206		5,064
Thereafter		9,770		416		10,186
	$	38,032	$	825	$	38,857

(1) Cash represents the amounts received through June 30, 2012 as part of the monetization of certain hedge contracts. Non-cash represents monetized hedges in which the cash will be received when the underlying hedge contract settles in calendar year 2013.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

As of June 30, 2012, we had the following contracts outstanding Asset (Liability) and Fair Value Gain (Loss) (in thousands):

	Crude Oil											Natural Gas
						Total										Total				Total
Period	Volume (MBbls)			Contract Price(1)		Asset (Liability)			Fair Value Gain (Loss)			Volume (MMBtu)		Contract Price(1)		Asset (Liability)		Fair Value Gain		Asset (Liability)			Fair Value Gain (Loss)(2)
Crude Oil – WTI Collars
7/12 – 12/12		1,417		$	72.60/$100.19	$	12		$	(404	)									$	12		$	(404	)
1/13 – 12/13		1,664			73.57/105.63		2,149			536											2,149			536
							2,161			132											2,161			132
Three-Way Collars
1/13 – 12/13		1,825			70/90/136.32		11,573			4,134											11,573			4,134
1/14 – 12/14		3,650			70/90/137.14		23,496			8,528											23,496			8,528
							35,069			12,662											35,069			12,662
Put Spreads
7/12 – 12/12		2,760			75.00/85.00		8,210			4,076											8,210			4,076
Swaps
7/12 – 12/12		92			86.60		40			(94	)										40			(94	)
1/13 – 12/13		183			86.60		(326	)		(188	)										(326	)		(188	)
7/12 – 12/12		(92	)		88.20		(187	)													(187	)
1/13 – 12/13		(183	)		88.20		37														37
							(436	)		(282	)										(436	)		(282	)
Crude Oil – Brent Collars
7/12 – 12/12		920			87.00/114.24		848			179											848			179
1/13 – 12/13		2,781			80.00/126.78		7,703			4,491											7,703			4,491
							8,551			4,670											8,551			4,670
Put Spreads
7/12 – 12/12		460			65.00/85.00		(127	)													(127	)
Call Spread
1/13 – 12/13													1,825	$	3.75/$4.75	$	460				460
Three-Way Collars
7/12 – 12/12		1,785			67.42/87.42/127.76		3,012			618			5,520		4.07/4.93/5.87		3,777		2,455		6,789			3,073
1/13 – 12/13		1,643			61.67/83.33/140.69		5,385			2,002			10,950		4.07/4.93/5.87		7,009		4,556		12,394			6,558
1/14 – 12/14		1,278			66.43/86.43/141.36		4,922			1,440											4,922			1,440
							13,319			4,060							10,786		7,011		24,105			11,071
Total Gain on Derivatives						$	66,747		$	25,318						$	11,246	$	7,011	$	77,993		$	32,329

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

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

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):

	Asset Derivative Instruments								Liability Derivative Instruments
	June 30, 2012				June 30, 2011				June 30, 2012				June 30, 2011
	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Commodity Derivative Instruments designated as hedging instruments:
Derivative financial instruments		Current	$	66,716		Current	$	6,048		Current	$	34,462		Current	$	58,593
		Non-Current		103,462		Non-Current		1,248		Non-Current		58,229		Non-Current		72,719
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments		Current		326		Current		2,310		Current		83		Current		3
		Non-Current		451		Non-Current		948		Non-Current		188		Non-Current		—
Total			$	170,955			$	10,554			$	92,962			$	131,315

The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands):

	Year Ended June 30,
	2012			2011			2010
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(438	)	$	58,185		$	(4,008	)
Natural gas sales		(28,163	)		(37,874	)		(41,598	)
Total cash settlements		(28,601	)		20,311			(45,606	)
Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments
Ineffective portion of commodity derivative instruments		(3,479	)		(21	)		1,480
Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market gain		(4,542	)		(3,686	)		(11,430	)
Unrealized mark to market (gain) loss		793			(1,856	)		5,211
Total gain on derivative financial instruments		(7,228	)		(5,563	)		(4,739	)
Total (gain) loss	$	(35,829	)	$	14,748		$	(50,345	)

86

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

The cash flow hedging relationship of our derivative instruments was as follows (in thousands):

Location of (Gain) Loss	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Year Ended June 30, 2012
Commodity Derivative Instruments	$	(126,087	)
Revenues				$	(22,372	)
(Gain) loss on derivative financial instruments							$	(3,479	)
Total	$	(126,087	)	$	(22,372	)	$	(3,479	)
Year Ended June 30, 2011
Commodity Derivative Instruments	$	96,190
Revenues				$	(7,422	)
(Gain) loss on derivative financial instruments							$	(21	)
Total	$	96,190		$	(7,422	)	$	(21	)
Year Ended June 30, 2010
Commodity Derivative Instruments	$	10,791
Revenues				$	(31,491	)
(Gain) loss on derivative financial instruments							$	1,480
Interest Expense					(2,258	)
Total	$	10,791		$	(33,749	)	$	1,480

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $49.7 million ($32.3 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position from counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At June 30, 2012, we had no deposits for collateral with our counterparties.

On June 26, 2006, we entered into an interest rate costless collar to mitigate the risk of loss due to changes in interest rates. The dollar amount hedged was $75 million with the interest rate collar being 5.45% to 5.75%. This instrument matured in April 2010. The impact of this collar on interest expense for the year ended June 30, 2010 was an increase of $2.9 million.

Note 10 — Stockholders’ Equity

Common Stock

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”). Our common stock trades on the NASDAQ and on the Alternative Investment Market of the

87

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 — Stockholders’ Equity  – (continued)

London Stock Exchange (“AIM”) under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. We have 200,000,000 authorized common shares, par value of $0.005 per share.

On November 3, 2010, we closed on concurrent offerings of common and preferred stock. We sold 12 million shares of our unrestricted common stock at $20.75 per share less $0.985 per share in underwriting commissions. Net proceeds from the common stock offering were approximately $237.2 million, after deducting underwriting commissions, but before other offering expenses.

On November 5, 2010, the underwriters exercised their over-allotment on the common stock offering resulting in the issuance of an additional 1.8 million common shares. Net proceeds from the sale of the 1.8 million shares of common stock were approximately $35.6 million, after deducting underwriting commissions, but before other offering expenses.

On December 14, 2009, we closed on a registered offering of 18,000,000 shares of $0.005 par value common stock at a price of $9.50 per share, less $0.50 per share underwriters’ commission. On December 28, 2009, the underwriters exercised their over-allotment option acquiring an additional 821,046 shares at $9.50 per share, less $0.50 per share in underwriters’ commissions. We received net proceeds of $188.0 million for the combined common stock offerings, after deducting $0.50 per share underwriters’ commissions and offering costs.

On May 2, 2012, our Board of Directors approved payment of a quarterly cash dividend of $0.07 per share to the holders of the Company’s common stock. The quarterly dividend was paid on June 15, 2012 to shareholders of record on June 1, 2012.

Preferred Stock

Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. The number of authorized preferred shares we are authorized to issue was increased to 7,500,000 shares from 2,500,000 shares, and approved by shareholders at the Annual General Meeting held in November 2011. Our board of directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Shares of previously issued preferred stock that have been cancelled are available for future issuance.

On November 3, 2010, we sold 1.15 million shares of 5.625% Perpetual Convertible Preferred Stock (“5.625% Preferred Stock”) at $250 per share, less $3.75 per share (1.5%) in underwriting commissions. Net proceeds to the Company from the sale of preferred stock were approximately $283.2 million, after deducting underwriting commissions, but before other offering expenses.

The 5.625% Preferred Stock is convertible into 9.8353 shares of the Company’s common stock or approximately $25.42 per share. On or after December 15, 2013, the Company may cause the 5.625% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of the Company’s common stock equals or exceeds 130% of the then-prevailing conversion price (currently $33.05).

On December 14, 2009, the Company sold 1,100,000 shares of 7.25% Perpetual Convertible Preferred Stock (“7.25% Preferred Stock”) at a $100 per share, less $3.00 per share (3%) in underwriting commissions. Net proceeds to the Company from the sale of preferred stock were approximately $106.6 million, after deducting underwriting commissions, but before other offering expenses.

The 7.25% Preferred Stock is convertible into 8.77192 shares of the Company’s common stock or approximately $11.40 per share. On or after December 15, 2014, the Company may cause the 7.25% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of the Company’s common stock equals or exceeds 150% of the then-prevailing conversion price (currently $17.10).

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 — Stockholders’ Equity  – (continued)

Dividends on both the 5.625% Perpetual Convertible Preferred Stock (“5.625% Preferred Stock”) and the 7.25% Perpetual Convertible Preferred Stock (“7.25% Preferred Stock”) are payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year.

Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, shares of the Company’s common stock, or a combination thereof. If the Company elects to make payment in shares of common stock, such shares shall be valued for such purposes at 95% of the market value of the Company’s common stock as determined on the second trading day immediately prior to the record date for such dividend.

Conversion of Preferred Stock

During June 2012, we canceled and converted a total of 103 shares of our 5.625% Preferred Stock into a total of 1,016 shares of common stock using a conversion rate of 9.8578 common shares per preferred share.

During February and March 2012, we cancelled and converted a total of 235,780 shares of our 5.625% Preferred Stock into a total of 2,318,961 shares of common stock. In addition to the stated conversion rate of 9.8353 common shares per preferred share, we paid cash of $6.1 million, of which $0.7 million was paid towards accrued dividends and the remaining $5.4 million was paid to induce the conversion.

During the year ended June 30, 2011, we entered into other private transactions with third parties related to the conversion of our 7.25% Preferred Stock. In addition to the stated conversion of 8.77192 common shares per preferred share, we made additional payments in stock and cash to induce the conversion.

During May and June 2011, we canceled and converted a total of 100,000 shares of our 5.625% Preferred Stock into common stock. In addition to the stated conversion rate of 9.83526 common shares per preferred share, we also issued additional common shares to induce the conversion.

On October 21, 2010, we launched an exchange offer for shares of our 7.25% Preferred Stock outstanding. The exchange offer provided for the issuance of 8.77192 shares of our unrestricted common stock per share of 7.25% Preferred Stock and a cash payment to induce the conversion. The exchange offer closed on November 19, 2010. A total of 517,970 shares of 7.25% Preferred Stock were canceled and exchanged for 4,543,583 shares of common stock and a cash payment of $10.5 million, which included accrued dividends of $0.7 million.

The following is a summary of the preferred stock exchanges for the year ended June 30, 2011 including the related inducements:

	Preferred Shares Exchanged		Common Shares Issued				Common Share Inducement Value		Cash Inducement		Other Expenses		Total Inducement Value
			Stated Conversion		Inducement
									(In thousands)
7.25% Preferred Stock		1,092,000		9,578,929		382,564	$	9,354	$	11,837	$	284	$	21,475
5.625% Preferred Stock		100,000		983,526		92,263		2,860		—		13		2,873
Total				10,562,455		474,827	$	12,214	$	11,837	$	297	$	24,348

At June 30, 2012, we have 814,117 shares of 5.625% Preferred Stock and 8,000 shares of 7.25% Preferred Stock issued and outstanding.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11 — Supplemental Cash Flow Information

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

	Year Ended June 30,
	2012		2011		2010
Cash paid for interest	$	103,346	$	96,624	$	84,336

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

	Year Ended June 30,
	2012			2011			2010
Financing of insurance premiums	$	22,211		$	19,853		$	—
Conversion of preferred stock to common stock		—			(12,391	)		—
Preferred stock dividends		(138	)		286			332
Derivative instruments premium financing acquired through financing		16,259			4,267			3,928
Additions to property and equipment by recognizing asset retirement obligations		(45,998	)		222,438			71,635

Note 12 — Employee Benefit Plans

The Energy XXI Services, LLC 2006 Long-Term Incentive Plan (“Incentive Plan”).  We maintain an incentive and retention program for our employees. Participation shares (or “Restricted Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. The Restricted Stock Units generally vest equally over a three-year period. When vesting occurs, we pay the employee an amount equal to the then current common share price times the number of Restricted Stock Units.

Performance Units

For fiscal 2010, 2011 and 2012, we also awarded performance units. Of the total performance units awarded, 25% are time-based performance units (“Time-Based Performance Units”) and 75% are Total Shareholder Return Performance-Based Units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vest equally over a three-year period.

Time-Based Performance Units.  The amount due the employee at the vesting date is equal to the grant date unit value of $5.00 plus the appreciation in the stock price over the performance period, multiplied by the number of units that vest. For the fiscal year 2010 grant, the initial stock price used in determining the change in stock price is $7.40 per share, for the fiscal year 2011 grant the initial stock price is $15.62 and for the fiscal year 2012 grant the initial stock price is $34.40.

TSR Performance-Based Units.  For each TSR Performance-Based Unit, the executive will receive a cash payment equal to the grant date unit value of $5.00 multiplied by (a) the cumulative percentage change in the price per share of the Company’s common stock from the date on which the TSR Performance-Based Units were granted (the “Total Shareholder Return”) and (b) the TSR Unit Number Modifier.

In addition, the employee may have the opportunity to earn additional compensation based on the Company’s Total Shareholder Return at the end of the third Performance Period.

At our discretion, at the time the Restricted Stock Units and Performance Units vest, employees will settle in either common shares or cash. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable. Historically, we have paid all vesting awards in cash. The July 21, 2012 vesting of the July 21, 2011, 2010 and 2009 Performance Unit awards were paid 50% in common stock and future vesting of the Performance Units may be paid in stock at the discretion of our board of directors.

90

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans  – (continued)

We recognized compensation expense related to our outstanding Restricted Stock Units and Performance Units as follows (in thousands):

	Year Ended June 30,
	2012		2011		2010
Restricted Stock Units	$	19,315	$	20,314	$	9,821
Performance Units		31,148		28,480		9,177
Total compensation expense recognized	$	50,463	$	48,794	$	18,998

As of June 30, 2012, we have 925,737 unvested Restricted Stock Units and 3,914,638 unvested Performance Based Units.

Restricted Shares

Restricted Shares activity is as follows:

	Number Of Shares			Grant-date Fair Value Per Share
Non-vested at June 30, 2010		81,644		$	24.75
Vested during fiscal 2011		(50,430	)
Non-vested at June 30, 2011		31,214			24.75
Vested during fiscal 2012		(31,214	)
Non-vested at June 30, 2012		—

We determine the fair value of the Restricted Shares based on the market price of our common stock on the date of grant. Compensation cost for the Restricted Shares is recognized on a straight line basis over the requisite service period. For the years ended June 30, 2012, 2011 and 2010, we recognized compensation expense of $49,000, $1.0 million and $1.6 million, respectively, related to our Restricted Shares.

Stock Purchase Plan

Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of our common stock that have either been purchased by us on the open market or that have been newly issued by us. During the years ended June 30, 2012, 2011 and 2010, we issued 305,401 shares, 282,047 shares and 129,239 shares, respectively, under the 2008 Purchase Plan.

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period. The current offering period is from July 1, 2012 to December 31, 2012. We use Black-Scholes Model to determine fair value, which incorporates assumptions to value stock-based awards. The shares issuable under Employee Stock Purchase Plan are included in calculating diluted earnings per share, if dilutive. As of June 30, 2012 there was no unrecognized compensation. The compensation expense recognized and shares issued under Employee Stock Purchase Plan were as follows (in thousands, except for shares):

	Year Ended June 30,
	2012		2011		2010
Compensation expense	$	729	$	567	$	417
Shares issued		46,985		115,323		163,682

91

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans  – (continued)

Stock Options

In September 2008, our board of directors granted 300,000 stock options to certain officers. These options to purchase our common stock were granted with an exercise price of $17.50 per share. These options vested over a three year period and may be exercised any time prior to September 10, 2018. As of June 30, 2012, 100,000 of the vested options have been exercised and the remaining 200,000 vested options have not been exercised.

A summary of our stock option activity and related information is as follows:

	Year Ended June 30,
	2012					2011					2010
	Shares Under Option			Weighted Ave. Exercise Price		Shares Under Option			Weighted Ave. Exercise Price		Shares Under Option			Weighted Ave. Exercise Price
Beginning balance		100,000		$	17.50		240,000		$	17.50		300,000		$	17.50
Granted		—			—		—			—		—			—
Vested		(100,000	)		17.50		(140,000	)		17.50		(60,000	)		17.50
Ending balance		—		$	17.50		100,000		$	17.50		240,000		$	17.50

Our net income for the years ended June 30, 2012, 2011 and 2010 includes approximately $0.1 million, $0.2 million and $1.1 million, respectively of compensation costs related to stock options.

We utilize the Black-Scholes model to determine fair value, which incorporates assumptions to value stock-based awards. The dividend yield on our common stock was based on actual dividends paid at the time of the grant. The expected volatility is based on historical volatility of our common stock. The risk-free interest rate is the related United States Treasury yield curve for periods within the expected term of the option at the time of grant.

Defined Contribution Plans

Our employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions that can vary from year to year. We also sponsor a qualified 401(k) Plan that provides for matching. The contributions under these plans were as follows (in thousands):

	Year Ended June 30,
	2012		2011		2010
Profit Sharing Plan	$	3,014	$	2,980	$	3,419
401(k) Plan		3,195		1,788		1,426
Total contributions	$	6,209	$	4,768	$	4,845

Note 13 — Related Party Transactions

We have a 20% interest in EXXI NGP. We account for this investment using the equity method. See Note 5 — Equity Method Investments.

92

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14 — Earnings per Share

Basic earnings per share of common stock is computed by dividing net income available for common stockholders by the weighted average number of shares of common stock outstanding during the year. Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of convertible preferred stock, restricted stock and other common stock equivalents. The following table sets forth the calculation of basic and diluted earnings per share (“EPS”) (in thousands, except per share data):

	Year Ended June 30,
	2012		2011		2010
Net income	$	335,827	$	64,655	$	27,320
Preferred stock dividends		13,028		12,600		4,320
Induced conversion of preferred stock		6,068		24,348		—
Net income available for common stockholders	$	316,731	$	27,707	$	23,000
Weighted average shares outstanding for basic EPS		77,310		66,356		40,992
Add dilutive securities		9,898		103		392
Weighted average shares outstanding for diluted EPS		87,208		66,459		41,384
Earnings per share
Basic	$	4.10	$	0.42	$	0.56
Diluted	$	3.85	$	0.42	$	0.56

For the years ended June 30, 2012, 2011 and 2010, 4,821, 11,219,687 and 5,207,877, respectively, common stock equivalents were excluded from the diluted average shares due to an anti-dilutive effect.

Note 15 — Commitments and Contingencies

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

Lease Commitments.  We have a non-cancelable operating lease for office space and other that expires on December 31, 2018. Future minimum lease commitments as of June 30, 2012 under the operating lease are as follows (in thousands):

Year Ending June 30,
2013	$	2,451
2014		2,261
2015		2,273
2016		2,122
2017		2,144
Thereafter		1,444
Total	$	12,695

Rent expense, including rent incurred on short-term leases, for the years ended June 30, 2012, 2011 and 2010 was approximately $2,493,000, $1,933,000 and $1,933,000, respectively.

Letters of Credit and Performance Bonds.  We had $225.5 million in letters of credit and $25.1 million of performance bonds outstanding as of June 30, 2012.

Line of Credit.  Our equity method investee, EXXI NGP, of which we own 20%, is a guarantor of a $100 million line of credit entered into by its wholly owned subsidiary, NGP on February 23, 2012. See Note 5 — Equity Method Investments.

93

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 — Commitments and Contingencies  – (continued)

Drilling Rig Commitments.  As of June 30, 2012, we have entered into four drilling rig commitments:

1)  November 4, 2011 to January 15, 2013 at $47,800 per day

2)  March 10, 2012 to August 6, 2012 at $65,000 per day

3)  April 1, 2012 to December 31, 2012 at $75,000 per day

4)  June 8, 2012 to August 16, 2012 at $140,000 per day

At June 30, 2012, future minimum commitments under these contracts totaled $32.3 million.

Note 16 — Income Taxes

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

During the year ended June 30, 2009, we incurred a pre-tax impairment loss related to our oil and gas properties due to the steep decline in global energy prices over that same time period. This loss is not deductible for tax purposes until the impaired properties are depleted or disposed of. As a result of this impairment, for the year ending June 30, 2012 we remain in a position of cumulative reporting losses for the preceding reporting periods. The volatility of energy prices and uncertainty of when energy prices may stabilize continues to be problematic and not readily determinable by our management. At this date, this general fact pattern does not allow us to project sufficient sources of future taxable income to offset our tax loss carryforwards and net deferred tax assets in the U.S. Under these current circumstances, it is management’s opinion that the realization of these tax attributes beyond the reversal of existing taxable temporary differences does not reach the “more likely than not” criteria under ASC 740 (formerly known as FAS 109). As a result, during the year ended June 30, 2009 we established a valuation allowance of $175.0 million, and have subsequently adjusted this allowance downward by $92.7 million primarily due to the presence of pre-tax income in the subsequent years. This results in an ending valuation allowance of $82.3 million at June 30, 2012. Management continues to monitor this situation closely, and the results from any change in judgment reflecting a change in the underlying facts will be reflected in the period of the factual change.

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

	Year Ended June 30,
	2012		2011		2010
	(In Thousands)
U.S. income	$	346,887	$	47,751	$	12,794
Non-U.S. income		27,586		29,166		30,770
Income before income taxes	$	374,473	$	76,917	$	43,564

94

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Income Taxes  – (continued)

The components of our income tax provision are as follows:

	Year Ended June 30,
	2012			2011		2010
	(In Thousands)
Current
United States	$	—		$	—	$	—
Non U.S.		—			—		—
State		(53	)		93		6
Total current		(53	)		93		6
Deferred
United States		38,699			12,169		16,238
State		—			—		—
Total deferred		38,699			12,169		16,238
Total income tax provision	$	38,646		$	12,262	$	16,244

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

	Year Ended June 30,
	2012			2011			2010
	(In Thousands)
Income before income taxes	$	374,473		$	76,917		$	43,564
Statutory rate		35	%		35	%		35	%
Income tax expense computed at statutory rate		131,066			26,921			15,247
Reconciling items
Federal withholding obligation		10,371			10,343			10,343
Nontaxable foreign income		(9,655	)		(10,208	)		(10,770	)
Change in valuation allowance		(26,996	)		(25,290	)		(40,332	)
Revaluation of tax attributes		(22,405	)		7,186			—
Debt cancelation – bond repurchase		(52,583	)		—			40,460
State income taxes, net of federal tax benefit		(53	)		60			4
Non-deductible executive compensation and other-net		8,901			3,250			1,292
Tax provision	$	38,646		$	12,262		$	16,244

95

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Income Taxes  – (continued)

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

	June 30,
	2012			2011
	(In Thousands)
Deferred tax assets
Asset retirement obligation	$	105,495		$	13,287
Tax loss carryforwards on U.S. operations		226,927			66,945
Derivative instruments and other		—			45,843
Accrued interest expense		67,701			55,601
Deferred interest expense under IRC Sec. 162(j)		60,403			—
Employee benefit plans		14,845			16,793
Deferred state taxes		20,034			5,479
Other		7,311			—
Total deferred tax assets		502,716			203,948
Deferred tax liabilities
Derivative instruments and other		19,404			—
Oil, natural gas properties and other property and equipment		406,376			17,553
Federal withholding obligation		58,029			47,658
Cancellation of debt		9,680			6,451
Tax partnership activity		31,159			16,468
Other		—			4,063
Total deferred tax liabilities		524,648			92,193
Valuation allowance		82,348			109,344
Net deferred tax asset (liability)	$	(104,280	)	$	2,411
Reflected in the accompanying balance sheet as Non-current deferred tax asset (liability)	$	(104,280	)	$	2,411

The total change in deferred tax assets and liabilities in the year ended June 30, 2012 reflects a $67.9 million decrease in the deferred tax liability related to items recorded in other comprehensive income. This decrease resulted in a deferred tax liability at June 30, 2012 of $31 million related to other comprehensive income which is included in the derivative instruments line.

At June 30, 2012, we have a federal tax loss carryforward (“NOLs”) of approximately $648.4 million, a state income tax loss carryforward of approximately $385.30 million. The regular federal income tax NOLs will expire in various amounts beginning in 2026 and ending in 2029.

Section 382 of the Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an “ownership change” and Code Section 383 provides similar rules for other tax attributes, e.g., capital losses. In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation by more than 50 percentage points over a three year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382 determined by multiplying the value of the Company’s stock at the time of the ownership change by the applicable long-term tax exempt rate (ranging between approximately 3.0% and 4.5%). Any unused annual limitation may be carried over to subsequent years. The amount of the limitation may, under certain circumstances, be increased by the built-in gains held by the Company at the

96

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Income Taxes  – (continued)

time of the ownership change that are recognized in the five year period after the change. The Company experienced an ownership change on June 20, 2008, and a second ownership change on November 3, 2010. Based upon the Company’s determination of its annual limitation related to this ownership change, management believes that Section 382 should not otherwise limit the Company’s ability to utilize its federal or state NOLs or other attribute carryforwards during their applicable carryforward periods. Management will continue to monitor the potential impact of Code Sections 382 and 383 in future periods with respect to NOL and other tax carryforwards and will reassess realization of these carryforwards periodically.

We adopted the provisions of ASC 740-10 (formally known as FIN 48) and applied the guidance of ASC 740-10 as of July 1, 2007. As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of ASC 740-10 or have any gross unrecognized tax benefit. At June 30, 2012, we did not have any ASC 740-10 liability or gross unrecognized tax benefit.

We filed our initial tax returns for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 through 2011. The tax years ended June 30, 2009 through 2011 remain open to examination under the applicable statute of limitations in the U.S. in which the Company and its subsidiaries file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not begin to run until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law.

We have historically paid no significant cash taxes primarily due to the presence of our NOLs. However, if current income trends continue, we could be responsible for making cash tax payments in fiscal 2014 from application of the alternative minimum tax (AMT) under current law.

Note 17 — Concentrations of Credit Risk

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

Shell Trading Company (“Shell”) accounted for approximately 32%, 61% and 62% of our total oil and natural gas revenues during the years ended June 30, 2012, 2011 and 2010, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 37% and 22% of our total oil and natural gas revenues during the years ended June 30, 2012 and 2011, respectively. J.P. Morgan Ventures Energy Corporation (“J.P. Morgan”) accounted for 18% of our total oil and natural gas revenues during the year ended June 30, 2012. 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, ExxonMobil and or J.P. Morgan curtailed their purchases.

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

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

97

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Concentrations of Credit Risk  – (continued)

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

Note 18 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

The carrying amounts approximate fair value for cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable due to the short-term nature or maturity of the instruments.

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 — Derivative Financial Instruments.

The fair values of our stock based units are based on period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model is used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on TSR Performance-Based Units valuation.

Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

• Level 1 — quoted prices in active markets for identical assets or liabilities.

• Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

• Level 3 — unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

98

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 18 — Fair Value of Financial Instruments  – (continued)

The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

	Level 1				Level 2
	As of June 30,				As of June 30,
	2012		2011		2012		2011
Assets:
Oil and natural gas derivatives					$	170,955	$	10,554
Liabilities:
Oil and natural gas derivatives					$	92,962	$	131,315
Restricted stock units	$	15,124	$	17,866
Time-based performance units		4,434		3,611
Total liabilities	$	19,558	$	21,477	$	92,962	$	131,315

The following table describes the changes to our Level 3 financial instruments (in thousands):

	Level 3
	Year Ended June 30,
	2012			2011
Liabilities:
Performance-based performance units
Balance at beginning of year	$	20,305		$	7,846
Vested		(23,807	)		(11,778	)
Grants charged to income		26,357			24,237
Balance at end of year	$	22,855		$	20,305

99

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 19 — Prepayments and Accrued Liabilities

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

	June 30,
	2012		2011
Prepaid expenses and other current assets
Advances to joint interest partners	$	12,966	$	14,696
Insurance		30,515		23,230
Inventory		4,849		6,305
Royalty deposit		2,443		1,959
Stock held for future issuance to employees		8,786		—
Other		3,470		1,561
Total prepaid expenses and other current assets	$	63,029	$	47,751
Accrued liabilities
Advances from joint interest partners	$	301	$	437
Employee benefits and payroll		53,541		53,789
Interest payable		3,721		5,806
Accrued hedge payable		136		14,095
Undistributed oil and gas proceeds		54,484		31,880
Other		6,635		5,150
Total accrued liabilities	$	118,818	$	111,157

Note 20 — Subsequent Events

In July 2012, we entered into a note to finance a portion of our insurance premiums. The note is for a total face amount of $3.6 million and bears interest at an annual rate of 1.667%. The note amortizes over the remaining term of the insurance, which matures May 1, 2013.

On July 18, 2012, our Board of Directors approved payment of a quarterly cash dividend of $0.07 per share to the holders of the Company’s common stock. The quarterly dividend will be paid on September 14, 2012 to shareholders of record on August 31, 2012.

On July 19, 2012, EXXI NGP, in which we have a 20% interest, acquired interest in certain oil and gas fields owned by EP Energy, through its wholly-owned subsidiary NGP. See Note 5 — Equity Method Investments.

Note 21 — Selected Quarterly Financial Data — Unaudited

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

	Year Ended June 30, 2012
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter
Revenues	$	341,946	$	335,996	$	340,578	$	284,883
Operating income		116,410		126,805		137,986		102,083
Net income	$	81,155	$	91,252	$	97,089	$	66,331
Preferred stock dividends		2,877		2,739		3,706		3,706
Induced conversion of preferred stock		10		6,058		—		—
Net income (loss) available for common stockholders	$	78,268	$	82,455	$	93,383	$	62,625
Net income per share attributable to common stockholders(1)
Basic	$	0.99	$	1.06	$	1.22	$	0.82
Diluted		0.93		1.04		1.11		0.76

100

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 21 — Selected Quarterly Financial Data — Unaudited  – (continued)

	Year Ended June 30, 2011
	Fourth Quarter		Third Quarter		Second Quarter			First Quarter
Revenues	$	282,781	$	258,636	$	173,953		$	144,000
Operating income		78,624		64,105		44,572			21,622
Net income	$	35,217	$	18,371	$	10,934		$	133
Preferred stock dividends		3,902		4,278		2,426			1,994
Induced conversion of preferred stock		4,508		44		19,796			—
Net income (loss) available for common stockholders	$	26,807	$	14,049	$	(11,288	)	$	(1,861	)
Net income (loss) per share attributable to common stockholders(1)
Basic	$	0.36	$	0.19	$	(0.17	)	$	(0.04	)
Diluted		0.36		0.19		(0.17	)		(0.04	)

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

Note 22 — Supplementary Oil and Gas Information — Unaudited

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

	Year Ended June 30,
	2012			2011		2010
	(In Thousands)
Oil and Gas Activities
Exploration costs	$	183,397		$	98,133	$	51,030
Development costs		383,495			180,191		92,949
Total		566,892			278,324		143,979
Administrative and Other		3,778			2,909		1,133
Total capital expenditures		570,670			281,233		145,112
Property acquisitions
Proved		6,401			722,551		250,795
Unproved		—			289,711		42,242
Total acquisitions		6,401			1,012,262		293,037
Asset retirement obligations, insurance proceeds and other – net		(55,399	)		205,702		17,996
Total costs incurred	$	521,672		$	1,499,197	$	456,145

Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs are transferred to proved properties as the properties are evaluated or over the life of the reservoir. The wells in progress will be transferred into the amortization base once the results of the drilling activities are known.

101

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 22 — Supplementary Oil and Gas Information — Unaudited  – (continued)

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

	June 30,
	2012		2011		2010
	(In Thousands)
Unevaluated properties	$	166,692	$	324,549	$	85,211
Wells in progress		252,068		142,744		59,099
	$	418,760	$	467,293	$	144,310

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the U.S. are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise that those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

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

	Crude Oil (MBbls)			Natural Gas (MMcf)			Total (MBOE)
Proved reserves at June 30, 2009		30,873			133,415			53,109
Production		(5,352	)		(15,534	)		(7,941	)
Extensions and discoveries		698			5,637			1,638
Revisions of previous estimates		3,643			7,403			4,877
Purchases of minerals in place		17,621			37,862			23,931
Proved reserves at June 30, 2010		47,483			168,783			75,614
Production		(8,553	)		(24,533	)		(12,642	)
Extensions and discoveries		3,056			39,555			9,649
Revisions of previous estimates		2,155			(43	)		2,148
Reclassification of proved undeveloped		(2,917	)		(4,579	)		(3,681	)
Purchases of minerals in place		37,115			97,591			53,380
Sales of reserves		(1,133	)		(40,458	)		(7,876	)
Proved reserves at June 30, 2011		77,206			236,316			116,592
Production		(11,172	)		(29,824	)		(16,143	)
Extensions and discoveries		11,444			27,821			16,081
Revisions of previous estimates		9,098			(23,281	)		5,217
Reclassification of proved undeveloped		(1,783	)		(2,042	)		(2,123	)
Proved reserves at June 30, 2012		84,793			208,990			119,624

102

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 22 — Supplementary Oil and Gas Information — Unaudited  – (continued)

	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed reserves
June 30, 2009		20,183		82,432		33,922
June 30, 2010		36,970		93,610		52,572
June 30, 2011		59,234		134,024		81,572
June 30, 2012		63,308		110,310		81,693
Proved undeveloped reserves
June 30, 2009		10,690		50,983		19,187
June 30, 2010		10,513		75,173		23,042
June 30, 2011		17,972		102,292		35,020
June 30, 2012		21,485		98,680		37,931

Proved undeveloped (“PUD”) reserve estimates of 37,931 MBOE as of June 30, 2012 increased by 8% over the 35,020 MBOE of PUD reserves estimated at the end of June 30, 2011. During fiscal 2012, 1.6 MMBOE of previously proved undeveloped reserves were converted to proved developed reserves principally through drilling activity in West Delta 73 and South Timbalier 54.

During fiscal 2012, a total of $24.3 million was spent on projects associated with reserves that were carried as PUD reserves at the end of fiscal year 2011.

Four PUD’s were not converted into proved developed reserves within the five year requirement at June 30, 2012. Main Pass 61 OCS-G 16493 A-3 and Main Pass 73 B-19 ST are both sidetrack PUDs, but are still producing and cannot be drilled until the PDP zone in each well depletes. South Pass 49 OCS-G 2177 A-2 ST and A-10 ST were not converted because SP 49’s “A” platform is located in a mudslide area and had not been certified for drilling until May 2012, when Bureau of Safety and Environmental Enforcement (“BSEE”) certified that the platform met conditions for acceptance criteria.

During the year ended June 30, 2012 proved reserve estimates were reduced by 2.1 MMBOE from one PUD, ST 21 Chardonnay, due to the five year development rule.

Standardized Measure of Discounted Future Net Cash Flows

A summary of the standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves is shown below. Future cash inflows as of June 30, 2012 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $115.08 per barrel of oil (calculated using the unweighted average first-day-of-the-month Heavy Louisiana Sweet posted prices during the 12-month period ending on June 30, 2012). The report forecasts crude oil and NGL production separately. The average realized adjusted product prices weighted by production over the remaining lives of the properties, used to determine future net revenues were $113.36 per barrel of oil and $56.92 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials.

The $113.36 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $95.67 per barrel (differential of +$17.69 per barrel), and an unweighted average first-day-of-the-month Brent price of $112.49 per barrel (differential of +$0.87 per barrel)

For natural gas, the average Henry Hub price used was $3.15 per MMBtu, prior to adjustments for energy content, transportation fees, and regional price differentials (calculated using the unweighted average first-day-of-the-month Henry Hub spot price). The average adjusted realized gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $3.296 per MCF after adjusting for energy content, transportation fees, and regional price differentials.

103

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 22 — Supplementary Oil and Gas Information — Unaudited  – (continued)

For the years ended June 30, 2011 and 2010, West Texas Intermediate crude oil prices used were $90.09 per barrel and $75.76 per barrel, respectively and Henry Hub natural gas prices used were $4.21 per MMBtu and 4.10 per MMBtu, respectively. We used costs and statutory tax rates (adjusted for tax credits and other items) that relate to our existing proved crude oil and natural gas reserves.

The standardized measure of discounted future net cash flows related to proved oil and gas reserves as of June 30, 2012, 2011 and 2010 are as follows (in thousands):

	June 30,
	2012		2011		2010
Future cash inflows	$	10,009,119	$	7,989,182	$	4,121,293
Less related future
Production costs		2,737,969		2,188,918		1,024,492
Development and abandonment costs		1,304,007		1,184,728		639,524
Income taxes		1,377,363		1,073,278		398,399
Future net cash flows		4,589,780		3,542,258		2,058,878
Ten percent annual discount for estimated timing of cash flows		1,284,291		980,865		509,727
Standardized measure of discounted future net cash flows	$	3,305,489	$	2,561,393	$	1,549,151

Changes in Standardized Discounted Future Net Cash Flows

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

	Year Ended June 30,
	2012			2011			2010
Beginning of year	$	2,561,393		$	1,549,151		$	1,005,276
Revisions of previous estimates
Changes in prices and costs		855,382			362,283			300,591
Changes in quantities		153,537			59,149			27,735
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		604,266			111,053			27,651
Purchases of reserves in place		—			1,553,858			703,456
Sales of reserves in place		—			(171,264	)		—
Accretion of discount		333,748			184,892			105,977
Sales, net of production and gathering and transportation costs		(968,956	)		(604,057	)		(352,102	)
Net change in income taxes		(215,873	)		(476,319	)		(245,269	)
Changes in rate of production		(13,438	)		(72,069	)		(31,104	)
Development costs incurred		24,519			114,710			108,864
Changes in abandonment costs and other		(29,089	)		(49,994	)		(101,924	)
Net change		744,096			1,012,242			543,875
End of year	$	3,305,489		$	2,561,393		$	1,549,151

104

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

None.

Item 9A.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and our principal financial officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of the end of the period covered by this Form 10-K.

Management’s Annual Report on Internal Control over Financial Reporting

Management’s Report on Internal Control over Financial Reporting is included in Item 8 of this Form 10-K on Page 63 and is incorporated herein by reference.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our quarterly period ended June 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information

None.

105

PART III

Item 10.  Directors, Executive Officers and Corporate Governance

We have adopted a Code of Business Conduct and Ethics, which covers a wide range of business practices and procedures. The Code of Business Conduct and Ethics also represents the code of ethics applicable to our principal executive officer, principal financial officer, and principal accounting officer or controller and persons performing similar functions (“senior financial officers”). A copy of the Code of Business Conduct and Ethics is available on our website www.energyxxi.com under “Management Team —  Corporate Governance.”. We intend to disclose any amendments to or waivers of the Code of Business Conduct and Ethics on behalf of our senior financial officers on our website www.energyxxi.com under “Investor Relations” and “Corporate Governance” promptly following the date of the amendment or waiver.

Pursuant to general instruction G to Form 10-K, the remaining information required by this Item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

Item 11.  Executive Compensation

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

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

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

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

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

Item 14.  Principal Accounting Fees and Services

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

106

PART IV

Item 15.  Exhibits, Financial Statement Schedules

(a) The following documents are filed as a part of this Form 10-K or incorporated by reference:

(1) Financial Statements

	Page
Reports of Independent Registered Public Accounting Firm		64
Consolidated Balance Sheets as of June 30, 2012 and 2011		66
Consolidated Statements of Income for the Years Ended June 30, 2012, 2011 and 2010		67
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended June 30, 2012, 2011 and 2010		68
Consolidated Statements of Stockholders’ Equity for the Years Ended June 30, 2012, 2011 and 2010		69
Consolidated Statements of Cash Flows for the Years Ended June 30, 2012, 2011 and 2010		70
Notes to Consolidated Financial Statements		71

(2) Financial Statement Schedules

All schedules are omitted because they are either not applicable or required information is shown in the consolidated financial statements or notes thereto.

(3) Exhibits

The exhibits required to be filed pursuant to the requirements of Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this Form 10-K and are incorporated herein by reference.

107

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 9^th day of August 2012.

ENERGY XXI (BERMUDA) LIMITED

By: /s/ JOHN D. SCHILLER, JR.

John D. Schiller, Jr.
Chairman of the Board and
Chief Executive Officer

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

Signature	Title	Date
/s/ JOHN D. SCHILLER, JR. John D. Schiller, Jr.	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)	August 9, 2012
/s/ DAVID WEST GRIFFIN David West Griffin	Chief Financial Officer and (Principal Financial Officer and Principal Accounting Officer)	August 9, 2012
/s/ WILLIAM COLVIN William Colvin	Director	August 9, 2012
/s/ PAUL DAVISON Paul Davison	Director	August 9, 2012
/s/ DAVID M. DUNWOODY David M. Dunwoody	Director	August 9, 2012
/s/ CORNELIUS DUPRÉ II Cornelius Dupré II	Director	August 9, 2012
/s/ HILL A. FEINBERG Hill A. Feinberg	Director	August 9, 2012
/s/ KEVIN S. FLANNERY Kevin S. Flannery	Director	August 9, 2012

108

EXHIBIT INDEX

Exhibit Number	Description	Originally Filed as Exhibit	File Number
3.1	Altered Memorandum of Association of Energy XXI (Bermuda) Limited	3.1 to the Company’s Form 8-K filed on November 9, 2011	001-33628
3.2	Bye-Laws of Energy XXI (Bermuda) Limited	3.2 to the Company’s Form 8-K filed on November 9, 2011	001-33628
4.1	Investor Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) Limited, Sunrise Securities Corp. and Collins Steward Limited	4.1 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
4.2	Registration Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) and the investors named therein	4.2 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
4.3	Indenture, dated December 17, 2010, by and among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as trustee	4.1 to Form 8-K filed on December 22, 2010	001-33628
4.4	Registration Rights Agreement, dated as of December 17, 2010, by and among Energy XXI Gulf Coast, Inc., the Guarantors named therein and the Initial Purchasers named therein	4.2 to Form 8-K filed on December 22, 2010	001-33628
4.5	Indenture dated as of February 25, 2011 among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee	4.1 to Form 8-K filed on February 28, 2011	001-33628
4.6	Registration Rights Agreement dated as of February 25, 2011 among Energy XXI Gulf Coast, Inc., the Guarantors named therein and the Initial Purchaser named therein	4.2 to Form 8-K filed on February 28, 2011	001-33628
10.1†	2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.5 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.2†	Form of Restricted Stock Grant Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.6 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.3†	Form of Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.7 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.4†	Appointment letter dated August 31, 2005 for William Colvin	10.8 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.5†	Appointment letter dated August 31, 2005 for David Dunwoody	10.9 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639

109

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.6†	Appointment letter dated April 16, 2007 for Hill Feinberg	10.10 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.7†	Appointment letter dated April 24, 2007 for Paul Davison	10.11 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.8	Letter Agreement dated September 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.	10.12 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.9	Assumption and Indemnity Agreement dated September 15, 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.	10.13 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.10†	2006 Long-Term Incentive Plan of Energy XXI Services, LLC (as amended for fiscal year 2008)	10.1 to Form S-8 filed on November 30, 2007	333-147731
10.11†	Form of Notice of Grant of Stock Option together with Form of Stock Option Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.25 to Form 10-K filed on September 11, 2008	001-33628
10.12†	Energy XXI Services, LLC Directors’ Deferred Compensation Plan	10.1 to Form 8-K filed on September 10, 2008	001-33628
10.13†	Employment Agreement of John D. Schiller, Jr., effective September 10, 2008	10.1 to Form 8-K filed on September 11, 2008	001-33628
10.14†	Separation Agreement of Steve Weyel, effective August 25, 2010	10.1 to Form 8-K filed on August 23, 2010	001-33628
10.15†	Employment Agreement of David West Griffin, effective September 10, 2008	10.3 to Form 8-K filed on September 11, 2008	001-33628
10.16†	Form of Indemnification Agreement between Energy XXI (Bermuda) Limited and Indemnitees	10.1 to Form 8-K filed on November 5, 2008	001-33628
10.17†	Form of Indemnification Agreement Between Company Subsidiaries and Indemnitees	10.2 to Form 8-K filed on November 5, 2008	001-33628
10.18†	Energy XXI Services, LLC Employee Stock Purchase Plan	10.1 to Form 8-K filed on November 5, 2008	001-33628
10.19†	Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan	4.2 to Form S-8 filed on June 10, 2009	333-159868
10.20*†	Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Restricted Stock Unit Awards Agreement
10.21*†	Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Performance Unit Awards Agreement

110

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.22*†	Energy XXI Services, LLC, Employee Severance Plan (Amended and Restated August 11, 2010)
10.23†	Amended and Restated 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.1 to Form S-8 filed on December 15, 2009	333-163736
10.24	Purchase and Sale Agreement, dated as of November 20, 2009 by and between MitEnergy Upstream LLC and Energy XXI, Inc.	10.1 to Form 8-K filed November 24, 2009	001-33628
10.25	Seventh Amendment to Amended and Restated First Lien Credit Agreement, dated October 15, 2010	10.1 to Form 8-K filed on October 18, 2010	001-33628
10.26	Waiver Regarding Amended and Restated First Lien Credit Agreement, dated effective as of November 17, 2010	10.1 to Form 8-K filed on November 22, 2010	001-33628
10.27	Purchase and Sale Agreement, effective as of December 1, 2010, by and between Exxon Mobil Corporation, Mobil Oil Exploration and Producing Southeast Inc., ExxonMobil Pipeline Company, Mobil Eugene Island Pipeline Company and Energy XXI GOM, LLC	2.1 to Form 8-K filed on November 22, 2010	001-33628
10.28	Eighth Amendment to Amended and Restated First Lien Credit Agreement, dated November 17, 2010	10.1 to Form 8-K filed on November 23, 2010	001-33628
10.29	Waiver Regarding Amended and Restated First Lien Credit Agreement, dated effective as of December 1, 2010	10.1 to Form 8-K filed on December 2, 2010	001-33628
10.30	Second Amended and Restated First Lien Credit Agreement, dated as of May 5, 2011, among Energy XXI Gulf Coast, Inc., the various financial institutions and other parties from time to time parties thereto, as lenders, The Royal Bank of Scotland plc, as administrative Agent, and the other persons parties thereto in the capacities specified therein	10.1 to Form 8-K filed on May 6, 2011	001-33628
10.31	First Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 4, 2011	10.1 to Form 8-K filed on October 4, 2011	001-33628
10.32	Second Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 24, 2012	10.1 to Form 8-K filed on May 25, 2012	001-33628

111

Exhibit Number	Description	Originally Filed as Exhibit	File Number
12.1*	Ratio of Earnings to Fixed Charges –  Energy XXI Gulf Coast, Inc.
21.1*	Subsidiary List
23.1*	Consent of UHY LLP
23.2*	Consent of Netherland, Sewell & Associates, Inc.
31.1*	Rule 13a-14(a)/15d-14(a) Certification of the Chairman and Chief Executive Officer of Energy XXI (Bermuda) Limited
31.2*	Rule 13a-14(a)/15d-14(a) Certification of the Chief Financial Officer of Energy XXI (Bermuda) Limited
32.1#	Certification of the Chief Executive Officer and the Chief Financial Officer under 18 U.S.C. § 1350
99.1*	Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists
101.INS#	XBRL Instance Document
101.SCH#	XBRL Schema Document
101.CAL#	XBRL Calculation Linkbase Document
101.DEF#	XBRL Definition Linkbase Document
101.LAB#	XBRL Label Linkbase Document
101.PRE#	XBRL Presentation Linkbase Document

(*) Filed herewith.

(#) Furnished herewith.

(†) Executive Compensation Plan or Arrangement.

112