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, 2013
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	NASDAQ Global Select 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 $2,438,458,527 based on the closing sale price of $32.17 per share as reported on The NASDAQ Global Select Market on December 31, 2012, 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, 2013 was 75,799,146.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2013 Annual Meeting of Shareholders, which will be filed within 120 days of June 30, 2013, 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		21
Item 1B Unresolved Staff Comments		42
Item 2 Properties		42
Item 3 Legal Proceedings		42
Item 4 Mine Safety Disclosures		42
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		43
Item 6 Selected Financial Data		45
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations		48
Item 7A Quantitative and Qualitative Disclosures About Market Risk		69
Item 8 Financial Statements and Supplementary Data		72
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		114
Item 9A Controls and Procedures		114
Item 9B Other Information		114
PART III
Item 10 Directors, Executive Officers and Corporate Governance		115
Item 11 Executive Compensation		115
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		115
Item 13 Certain Relationships and Related Transactions, and Director Independence		115
Item 14 Principal Accounting Fees and Services		115
PART IV
Item 15 Exhibits, Financial Statement Schedules		116
Signatures		117

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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
Bcf	One billion cubic feet

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.

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 Securities and Exchange Commission (“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.

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

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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 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 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.

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

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

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

Zone is a stratigraphic interval containing one or more reservoirs.

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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.

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PART I

Item 1. Business

Overview

We are an independent oil and natural gas exploration and production company with operations focused in the U.S. Gulf Coast and the Gulf of Mexico. Our business strategy includes: (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, 2013, our estimated net proved reserves were 178.5 MMBOE, of which 75% was oil and 61% was proved developed. Natural gas liquids comprised 5% of our oil reserves. We are one of the largest oil producers on the Gulf of Mexico shelf and operate five of the largest fifteen oil fields in that area.

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 exploited 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 the 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 significantly increase the 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.

Exploring New Salt Plays.  Using a portion of our exploration budget, we explore for reserves in emerging plays beneath salt and in the shadow of salt, where seismic imaging can be difficult, but large structures with world-class resource potential exist. This includes salt-shadow joint ventures with Apache Corporation (“Apache JV”) in the Main Pass Area and with ExxonMobil in Vermillion Block 164 and 179, as well as the ultra-deep trend (depths in excess of 25,000 feet, either onshore or in water depths of less than

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150 feet). Since 2008, we have partnered with Freeport McMoRan Oil and Gas, LLC (formerly McMoRan Exploration Company and now acquired by Freeport McMoRan Copper and Gold, Inc.) (“Freeport McMoRan”) to explore the ultra-deep trend. Including the Davy Jones discovery well and Blackbeard West discovery well, the Freeport McMoRan operated group (in which we have various interests) has identified approximately 20 ultra-deep prospects near existing infrastructure. We have participated in 8 wells to date with our participations ranging from approximately 9% to 20%. In the ExxonMobil JV, the original Pendragon well encountered mechanical issues and was plugged and abandoned. Plans are to drill an offset well (Pendragon #2) and the Merlin prospect in fiscal 2014, making use of reprocessed 3D seismic data to improve imaging of the prospects. In the Apache JV we are employing wide angle azimuth (“WAZ”) seismic technology, one of the first ever on the Gulf of Mexico Shelf, to better image prospects. We are currently drilling the Heron prospect, with additional prospects expected to be drilled once we have analyzed the WAZ data and the Heron results. We target to spend less than 15% of our budgeted cash flow on our exploration activities on the salt plays.

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, the members of our senior management team average over 26 years of operating experience in the Gulf of Mexico. We also own an extensive seismic database covering approximately 7,460 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.  We currently operate approximately 94% of our proved reserves. 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, 2013 which represent approximately 86% of our net proved reserves and 89% of our future net revenues, discounted at 10% and are ranked based on highest proved reserves as of June 30, 2013.

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 the Outer Continental Shelf (“OCS”). The field, which was first discovered in 1962 by Humble Oil and Refining, is a large low relief faulted anticline. The field produces from Pleistocene through Upper Miocene aged sands trapped structurally on the high side closures over the large anticlinal feature from 1,500 feet to 13,000 feet. The field has produced in excess of 377 MMBOE. There are seven production platforms and 40 active and 28 shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2013 of 6.4 MBOE/Day (“MBOED”) accounted for approximately 14% of our net production for the quarter. Net proved reserves for the field, which is our largest field based upon net proved reserves, were 82% oil at June 30, 2013. This field is the eight largest oil field on the Gulf of Mexico Shelf.

Main Pass 61 Field.  We operate and have a 100% working interest in the Main Pass 61 field, located near the mouth of the Mississippi River in approximately 90 feet of water on OCS blocks Main Pass 60, 61, 62 and 63. The field was discovered by Pogo in 2000, and has produced in excess of 54 MMBOE since production first began in 2002, from four Upper Miocene sands. The primary producer is the J-6 Sand,

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which consists of a series of stratigraphic traps, located along a regional south dip, in a normal pressure environment. The two larger J-6 Sand stratigraphic pods are oil reservoirs that are being waterflooded to maximize recovery. There are 28 producing wells and three major production platforms located throughout the field. Net proved reserves for the field were 85% oil at June 30, 2013. The field’s average net production for the quarter ended June 30, 2013 of 6.9 MBOED accounted for approximately 15% of our net production for the quarter.

West Delta 30.  We operate and have a 100% working interest in the West Delta 30 block, located 21 miles offshore of Grand Isle, Louisiana in approximately 45 feet of water on the OCS. The field, which was discovered in 1948 by Humble Oil and Refining, is a large salt dome. Productive sands range from 2,000 feet to 17,500 feet in depth and generally produce using strong 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 735 MMBOE. There are 13 production platforms and 48 active wells located throughout the field. The field’s average net production for the quarter ended June 30, 2013 of 2.2 MBOED accounted for approximately 5% of our net production for the quarter. Net proved reserves for the field were 89% oil at June 30, 2013. This field is the second largest oil field on the Gulf of Mexico Shelf.

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 144 MMBOE. There are five production platforms and 30 active and 12 shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2013 of 2.8 MBOED accounted for approximately 6% of our net production for the quarter. Net proved reserves for the field were 76% oil at June 30, 2013.

South Pass 49 Field.  We have a 100% working interest in and operate the South Pass 49 field, 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. There are 17 active wells located throughout the field. The field is produced from one central production platform and has produced in excess of 116 MMBOE. The field’s average net production for the quarter ended June 30, 2013 of 4.1 MBOED accounted for approximately 9% of our net production for the quarter. Net proved reserves for the field were 74% oil at June 30, 2013.

Bayou Carlin Field.  We operate and have a 73% working interest in two wells in the Bayou Carlin Field, which is located onshore South Louisiana in St. Mary Parish. 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 6.7 MMBOE gross to date. In April 2011, the second well in the field, Landers #1 (Pontiff) was drilled to a total depth of 21,099 feet measured depth and has produced 5.4 MMBOE gross to date. The field’s average net production for the quarter ended June 30, 2013 of 4.6 MBOED accounted for approximately 10% of our net production for the quarter. Net proved reserves for the field were 95% natural gas at June 30, 2013.

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 the OCS. The field was originally discovered in 1948 by Humble Oil and Refinery and production begin in 1948. The field consists of two separate shallow piercement salt domes. Pleistocene through Miocene Sands are trapped structurally and stratigraphically from 6,000 feet to 13,000 feet in depth against the salt piercements. Radial faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 520 MMBOE. There are 13 production platforms and 56 active and 25 shut-in wells located throughout the field. The field’s average net production for the quarter ended June 30, 2013 of 7.0 MBOED accounted for approximately 15% of our net production for the quarter. Net proved reserves for the field were 70% oil at June 30, 2013. This field is the fourth largest oil field on the Gulf of Mexico Shelf.

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South Timbalier 21 Field.  We operate and have a 100% working interest in the South Timbalier 21 field, located six miles offshore of Lafourche Parish, Louisiana in approximately 50 feet of water on OCS blocks South Timbalier 21, 22, 23, 27 and 28, as well as on two state leases. The field was discovered by Gulf Oil in the late 1950s and has produced in excess of 327 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 43 smaller structures located throughout the field and 48 active wells. The field’s average net production for the quarter ended June 30, 2013 of 2 MBOED accounted for approximately 4% of our net production for the quarter. Net proved reserves for the field were 86% oil at June 30, 2012. This field is the tenth largest oil field on the Gulf of Mexico Shelf.

Main Pass 73 Field.  We operate and have a 100% working interest in 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 Energy, Inc. operated gas condensate wells on Main Pass 74. Average net production from the complex for the quarter ended June 30, 2013 of 1.9 MBOED accounted for approximately 4% of our net production for the quarter. Net proved reserves for the field were 72% oil at June 30, 2013.

Ultra-Deep Trend Exploration and Development Activity

We participate with Freeport McMoRan and Chevron U.S.A. Inc. in several prospects in the ultra-deep shelf and onshore area (“ultra-deep trend”) in the Gulf of Mexico. Data received to date from ultra-deep trend drilling with respect to the Davy Jones and Blackbeard West discovery wells in the Gulf of Mexico confirm geologic modeling that correlates objective sections on the shelf below the salt weld in the Miocene and older age sections to those productive sections seen in deepwater discoveries by other industry participants. In addition to Davy Jones and Blackbeard West, the Freeport McMoRan operated group has also identified approximately 20 ultra-deep prospects near existing infrastructure. Since 2008, the Ultra-Deep drilling program has included Blackbeard East, Lafitte, Blackbeard West, Lomond North, Blackbeard West No. 2 and Lineham Creek exploratory wells and delineation drilling at Davy Jones. We expect to have more than sufficient liquidity to fund our current commitments related to our ultra-deep trend exploration and development activity.

As previously reported, we have drilled two successful salt wells in the Davy Jones field. The Davy Jones No. 1, drilled to a true vertical depth 28,977 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, true vertical depth 30,422), 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. The Davy Jones field involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). As of June 30, 2013, our investment in both wells in the Davy Jones field totaled approximately $147 million.

Davy Jones.  The Davy Jones No. 1 well on South Marsh Island Block 230 in 19 feet of water 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 Freeport McMoRan operated group from obtaining a measurable flow rate. In January 2013, the operator re-perforated the Wilcox zones in the well with through-tubing perforating guns. Operations confirm that the perforations were open and that fluid could be injected through the perforations into the formation. A mini hydraulic fracture was performed indicating that the well could be fracture stimulated.

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Blackbeard East.  The Blackbeard East ultra-deep exploration by-pass well located in 80 feet of water on South Timbalier Block 144 was drilled to a true vertical 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 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 held the lease rights to South Timbalier Block 144 through August 17, 2012 and prior to the lease expiration submitted initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement (“BSEE”). The operator plans to test and complete the upper Miocene sands during 2014 using 20,000 psi equipment and conventional technologies. Additional plans for further development of the deeper zones continue to be evaluated. The Freeport McMoRan operated group’s ability to preserve the interest in Blackbeard East will require approval from the BSEE of the development plans. As of June 30, 2013, our investment in the well totaled approximately $51 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 true vertical 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, Upper Eocene, and Sparta carbonate. Freeport McMoRan's lease rights to Eugene Island Block 223 expired on October 8, 2012. Prior to the lease expiration, the operator submitted its initial development plans to complete and test the Frio/Cris R sands in the upper Eocene for Lafitte to the BSEE. This completion would have required the development of 30,000 psi equipment and the design development and procurement of such equipment would require an extended period of time leading up to the initiation of completion activities. For business reasons, in June 2013 the operator withdrew its Suspension of Production application requesting no further action from BSEE. As a result, interest in the Lafitte well and related leases effectively expired. As of June 30, 2013, 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 drilled in 70 feet of water on South Timbalier Block 168 was drilled to measured depth of 32,997 feet in 2008. Logs indicated four potential hydrocarbon bearing zones that require further evaluation. The well was temporarily abandoned.

The Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal 188 commenced drilling in 70 feet of water on November 25, 2011 and reached true vertical depth of 25,584 feet in January 2013. Through logs and core data, the operator has identified three potential hydrocarbon bearing Miocene sand sections between approximately 20,900 and 24,000 feet. Initial completion efforts are expected to focus on the development of approximately 50 net feet of laminated sands in the Middle Miocene located at approximately 24,000 feet. Additional development opportunities in the well bore include approximately 80 net feet of potential low-resistivity pay at approximately 22,400 feet and an approximate 75 foot gross section at approximately 20,900 feet. Pressure and temperature data indicate that a completion at these depths could utilize conventional equipment and technologies. Our investment in both Blackbeard West wells totaled approximately $57 million at June 30, 2013. Our operating partner’s current plans are to complete the well using 20,000 psi equipment and conventional technologies in late 2013 or early 2014.

Lineham Creek.  The Lineham Creek ultra deep exploration well, operated by Chevron U.S.A. Inc., which is located onshore in Cameron Parish, Louisiana commenced drilling on March 31, 2011. The well, which targets Eocene and Paleocene objectives below the salt weld was drilled to a total depth of 29,426 feet true vertical depth before sticking, the drill pipe was unable to be recovered. The proposed total drilling depth was 30,500 feet. The well encountered positive results in the Yegua sands section in November 2012. Detailed whole core and log data obtained will be used in evaluating future plans for all ultra-deep wells. The well is currently being sidetracked at 23,000 feet, and we expect the well to be drilled to 24,600 feet of true vertical depth in order to collect conventional cores from the Yegua sands section. As of June 30, 2013, our investment in the Lineham Creek well totaled approximately $17 million.

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Lomond North.  The Lomond North exploration prospect located onshore in St. Martin Parish, Louisiana, commenced drilling on September 19, 2012 in the Highlander area where multiple high potential prospects on an 80,000 acre position have been identified and is operated by Freeport McMoRan. The well which is targeting Eocene, Creataceous and Paleocene objectives below the salt weld, is currently drilling below 25,100 feet towards a proposed total depth of 30,000 feet. As of June 30, 2013, our investment in the Lomond North well totaled approximately $21 million. Completion design and planning is underway for long lead time items.

Reserve Estimation Procedures and Internal Controls over Reserve Estimates

Prior to fiscal year 2013, Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”) prepared evaluations on all of our proved reserves on a valuation basis and the estimates of proved oil and natural gas reserves attributable to our net interests in oil and gas properties. For fiscal year 2013, proved reserves were estimated and compiled for reporting purposes by our reservoir engineers and audited by NSAI as described in further detail under “Third Party Reserves Audit” below.

Our policies regarding internal controls over recording of reserves estimates require reserves to be in compliance with respect to reserve categorization and future producing rates, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance and prepared in accordance with the guidelines as set forth in the Society of Petroleum Engineers auditing standards. Our internal controls over reserves estimates 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 our reservoir engineers. 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 our internal reservoir engineers and the Director of Reserves and Business Planning to ensure the best estimate of remaining reserves;

• all relevant data is compiled in a computer database application, to which only authorized personnel are given access rights consistent with their assigned job function;

• reserve estimates are finally reviewed and approved by our Director of Reserves and Business Planning and certain members of senior management;

• the Audit Committee of our Board of Directors reviews significant reserve changes on an annual basis; and

• NSAI is engaged by the Audit Committee to perform an audit of our processes and the reasonableness of our estimates of proved reserves and has direct access to the Audit Committee.

Qualifications of Primary Internal Engineer and Third Party Engineers

Our Director of Reserves and Business Planning is the technical person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating reserve audits conducted by NSAI. He has 28 years of industry experience with positions of increasing responsibility. The Director of Reserves and Business Planning directly reports to our Chief Financial Officer.

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 an audit of our processes and the reasonableness of our estimates of proved reserves has been a practicing consulting petroleum engineer at NSAI since 2006 and has over 11 years of practical experience in petroleum engineering. He graduated with a Bachelor of Science in Petroleum Engineering and has a Masters of Business Administration degree. NSAI has informed us that he meets or exceeds the education, training, and experience requirements set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum

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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 5 NSAI petroleum engineers and geoscientists having an average industry experience of 15 years.

Because the estimates prepared by our senior reservoir engineering staff and audited by NSAI 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.

Technologies Used in Reserve Estimation

The SEC’s reserves rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. 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 internal reservoir engineers 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;

• future prices of oil and natural gas, which may vary considerably from those mandated by the SEC; and

• the judgment of the persons preparing the estimates.

Third-Party Reserves Audit

The estimate of reserves disclosed in this Form 10-K for fiscal 2013 is prepared by our reservoir engineers and we are responsible for the adequacy and accuracy of those estimates. We engaged NSAI to perform an audit of our processes and the reasonableness of our estimates of proved reserves. The reserves audit included a detailed review of all our major and minor fields and covered all of our proved reserves.

In connection with the fiscal 2013 reserves audit, NSAI prepared its own estimates of our proved reserves. In order to prepare its estimates of proved reserves, NSAI examined our estimates with respect to reserves quantities, future production rates, future net revenue, and the present value of such future net revenue. NSAI also examined our estimates with respect to reserves categorization and future producing rates, 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 the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.

When compared on a well by well basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. NSAI determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of

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Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves as of June 30, 2013, based upon their evaluation. NSAI concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI’s report is attached as Exhibit 99.1 to this Form 10-K.

Summary of Oil and Gas Reserves at June 30, 2013

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 our internal reservoir engineers and were audited by NSAI. 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, 2013 Based on Average Fiscal-Year Prices
	Oil MMBbls		Natural Gas Bcf		MMBOE		Percent of Total Proved			PV-10 (in thousands)(1)
Proved
Developed		80.2		175.6		109.5		61	%	$	3,553,992
Undeveloped		53.4		93.5		69.0		39	%		2,595,644
Total Proved		133.6		269.1		178.5					6,149,636
Future Income taxes											2,591,351
Less 10% discount											923,237
Future income taxes discounted at 10%											1,668,114
Standardized measure of future discounted net cash flows										$	4,481,522

(1) We refer to “PV-10” as the present value of estimated future net revenues of estimated proved reserves using a discount rate of 10%. This amount includes projected revenues less estimated production costs, abandonment costs and development costs. PV-10 is not a financial measure prescribed under accounting principles generally accepted in the U.S. (“U.S. GAAP”); therefore, the table reconciles this amount to the standardized measure of discounted future net cash flows, which is the most directly comparable U.S. GAAP financial measure. Management believes that the non-U.S. 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 U.S. 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 U.S. GAAP. Average prices (calculated using the average of the first-day-of-the-month commodity prices during the 12-month period ending on June 30, 2013) used in determining future net revenues were $91.60 per barrel of oil for West Texas Intermediate benchmark plus $16.64 per barrel for crude quality and location differentials, for a total of $108.24 per barrel. For NGL’s, the average price used was $43.64 per barrel. For natural gas, the average price used was $3.63 per MMBtu.

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Changes in Proved Reserves

Our proved developed reserve estimates increased by 27.8 MMBOE or 34% to 109.5 MMBOE at June 30, 2013 from 81.7 MMBOE at June 30, 2012. The increase was primarily due to:

• Additions of 11.2 MMBOE from drilling, recompletions, and wells returned to production with major additions at South Timbalier 54: 2.9 MMBOE, Main Pass 61: 2.5 MMBOE, Grand Isle 16: 1.7 MMBOE, and West Delta 73: 1.2 MMBOE;

• Improved well performance of 22.3 MMBOE was realized with major upward revisions at West Delta 73: 9.4 MMBOE, South Timbalier 54: 6.2 MMBOE, South Pass 49: 4.4 MMBOE, and Main Pass 61: 1.3 MMBOE;

• Offset by a 1 MMBOE downward performance revision at Main Pass 73, and 15.7 MMBOE of production; and

• Acquisitions of 8.0 MMBOE at Bayou Carlin: 7.0 MMBOE and Vermilion 164: 1.0 MMBOE.

Our proved undeveloped (“PUD”) reserve estimates increased by 31.1 MMBOE or 82% to 69.0 MMBOE at June 30, 2013 from 37.9 MMBOE at June 30, 2012. The increase was primarily due to:

• Additions of 36.3 MMBOE from identification of new proved undeveloped reserve locations were primarily at West Delta 73: 14.2 MMBOE, West Delta 30: 12.6 MMBOE, South Timbalier 54: 7 MMBOE, and Main Pass 61: 1.5 MMBOE;

• Acquisitions of 4.8 MMBOE at Vermilion 164: 3.3 MMBOE and West Delta 30: 1.5 MMBOE;

• Offset by 3.2 MMBOE of proved undeveloped reserves as of June 30, 2012 reserve report, which were converted to proved developed reserves and revised upward by 5.8 MMBOE in fiscal 2013. This resulted in a total of 9.0 MMBOE being converted to proved developed reserves during fiscal 2013 with the majority of the horizontal conversions at West Delta 73: 8.3 MMBOE. These proved undeveloped reserves were booked as directional/vertical in fiscal 2012 but we opted to drill these locations as horizontals instead, for higher production rates and ultimate recovery. The upward revision of 5.8 MMBOE in fiscal 2013 was a result of the higher realized initial production performance and higher estimated ultimate recovery from horizontals versus verticals; and

• 1.4 MMBOE of PUD reserves expired at South Timbalier 21: 0.4 MMBOE and South Pass 49: 1 MMBOE due to the five year development rule.

Two PUD reserve locations were not converted into proved developed reserves within the five year requirement and remain booked as proved undeveloped at June 30, 2013. Main Pass 61 OCS-G 16493 A-3 and Main Pass 73 B-19 ST are both PUD reserve locations to be sidetracked, but are still producing and cannot be drilled until the proved developed producing zone in each well depletes.

Development of Proved Undeveloped Reserves

Our PUD reserves at June 30, 2013 were 69 MMBOE. Future development costs associated with our PUD reserves at June 30, 2013 totaled approximately $1,000 million. In the fiscal year ended June 30, 2013, we developed approximately 8.4% of our PUD reserves included in our June 30, 2012 reserve report, consisting of 10 gross, 8.7 net wells at a net cost of approximately $113 million. We update and approve our reserves development plan on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total PUD reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors, including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of new acquisitions with PUD reserves. As scheduled in our long range plan that is reflected in the June 30, 2013 reserve report and further reflected in our initial budget for fiscal 2014, we expect to convert approximately 15% of our PUD reserves during fiscal year 2014, 24% during fiscal year 2015, 27% during fiscal year 2016, 16% during fiscal year 2017 and 18% during fiscal year 2018. We did not have any PUD

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well locations, other than the two PUD locations mentioned above, as of June 30, 2013 that were not scheduled to be converted into proved developed reserves within the five-year requirement as of June 30, 2013.

The following table discloses our progress toward the conversion of PUD reserves during the fiscal year ended June 30, 2013.

	Crude Oil and Natural Gas			Future Development Costs
	(MBOE)			(In thousands)
Proved undeveloped reserves at June 30, 2012		37,931		$	531,131
Extensions and discoveries		36,265			546,504
Revisions of previous estimates		384			5,377
Reclassification of proved undeveloped(1)		(1,416	)		(19,828	)
Changes in prices and costs		—			29,782
Purchases of reserves in place		4,836			72,877
Conversions to proved developed reserves		(8,993	)		(125,925	)
Total proved undeveloped reserves added		31,076			508,787
Proved undeveloped reserves at June 30, 2013		69,007		$	1,039,918

(1) Relates to the reclassification of PUD 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,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Productive wells drilled
Development		23.0		19.7		13.0		10.4		10.0		6.0
Exploratory		1.0		0.1		—		—		4.0		1.0
Total		24.0		19.8		13.0		10.4		14.0		7.0
Non productive dry wells drilled
Development		3.0		3.0		1.0		0.1		1.0		0.3
Exploratory		3.0		2.2		2.0		1.3		3.0		1.3
Total		6.0		5.2		3.0		1.4		4.0		1.6

Present Activities

As of June 30, 2013, six gross wells, representing approximately 3.6 net wells, were being drilled.

Delivery Commitments

We had no delivery commitments in the three years ended June 30, 2013.

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Productive Wells

Our working interests in productive wells follow.

	June 30,
	2013				2012
	Gross		Net		Gross		Net
Natural Gas		91		51		93		40
Crude Oil		372		284		357		270
Total		463		335		450		310

Acreage

Working interests in developed and undeveloped acreage follow.

	June 30, 2013
	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Onshore		38,700		36,856		109,876		40,295		148,576		77,151
Offshore		384,829		235,405		346,132		99,774		730,961		335,179
Total		423,529		272,261		456,008		140,069		879,537		412,330

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

	Year Ending June 30,
	2014				2015				2016
	Gross		Net		Gross		Net		Gross		Net
Onshore		3,138		2,049		2,279		8,483		40,734		20,643
Offshore		51,737		28,917		70,447		12,583		—		—
Total		54,875		30,966		72,726		21,066		40,734		20,643

Capital Expenditures, Including Acquisitions and Costs Incurred

Property acquisition costs:

	Year Ended June 30,
	2013			2012			2011
	(In Thousands)
Oil and Gas Activities
Development	$	636,406		$	383,495		$	180,191
Exploration		168,512			183,397			98,133
Acquisitions		161,164			6,401			1,012,262
Administrative and other		11,187			3,778			2,909
Capital expenditures, including acquisitions		977,269			577,071			1,293,495
Asset retirement obligations and other, net		(2,283	)		(55,399	)		205,702
Total costs incurred	$	974,986		$	521,672		$	1,499,197

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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,
	2013			2012			2011
Sales Volumes per Day
Natural gas (MMcf)		88.6			81.5			67.2
NGLs (MBbls)		2.3			2.8			1.7
Crude oil (MBbls)		26.0			27.7			21.7
Total (MBOE)		43.1			44.1			34.6
Percent of BOE from crude oil and NGLs		66	%		69	%		68	%
Average Sales Price
Natural gas per Mcf	$	3.48		$	2.97		$	4.15
Hedge gain per Mcf		0.47			0.94			1.54
Total natural gas per Mcf	$	3.95		$	3.91		$	5.69
NGLs per Bbl	$	38.38		$	53.73		$	48.28
Crude oil per Bbl	$	109.12		$	111.41		$	94.34
Hedge gain (loss) per Bbl		1.40			0.04			(7.34	)
Total crude oil per Bbl	$	110.52		$	111.45		$	87.00
Sales price per BOE	$	75.14		$	78.97		$	69.59
Hedge gain (loss) per BOE		1.81			1.77			(1.61	)
Total sales price per BOE	$	76.95		$	80.74		$	67.98

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, 2013. Our average daily production, average sales prices and production costs were as follows:

	Year Ended June 30,
	2013			2012			2011
West Delta 73
Sales Volumes per Day
Natural gas (MMcf)		9.0			6.0			9.8
NGLs (MBbls)		0.1			0.1			—
Crude oil (MBbls)		3.5			2.3			0.8
Total (MBOE)		5.1			3.4			2.5
Percent of BOE from crude oil and NGLs		71	%		71	%		32	%
Average Sales Price
Natural gas per Mcf	$	3.46		$	1.67		$	4.60
NGLs per Bbl	$	33.50		$	61.18		$	—
Crude oil per Bbl	$	109.11		$	111.33		$	103.49
Production Costs per BOE	$	18.54		$	21.30		$	9.71

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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,
	2013		2012		2011
Average Costs per BOE
Production costs
Lease operating expense
Insurance expense	$	2.08	$	1.77	$	2.21
Workover and maintenance		4.15		3.49		2.62
Direct lease operating expense		15.23		13.99		14.12
Total lease operating expense		21.46		19.25		18.95
Production taxes		0.33		0.45		0.26
Total production costs	$	21.79	$	19.70	$	19.21
Gathering and transportation	$	1.54	$	1.01	$	0.98
Depreciation, depletion and amortization rates	$	23.95	$	22.76	$	23.22

Sale of Certain Onshore Properties

In 2011, we closed on the sale 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” in this Form 10-K.

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 and 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 35%, 32% and 61% of our total oil and natural gas revenues during the years ended June 30, 2013, 2012 and 2011, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 37%, 37% and 22% of our total oil and natural gas revenues during the years ended June 30, 2013, 2012 and 2011, respectively. J.P. Morgan Ventures Energy Corporation (“J.P. Morgan”) accounted for 12% and 18% of our total oil and natural gas revenues during the years ended June 30, 2013 and 2012, respectively. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Shell, ExxonMobil 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. 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. Rates charged and terms of service for the interstate pipeline transportation of oil, natural gas liquids and other refined petroleum products also are regulated by FERC. FERC has established an indexing methodology 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

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in the EPAct 2005. The Commodity Futures Trading Commission (“CFTC”) also holds authority to regulate 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 regulate 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, or, for the CFTC, triple the monetary gain to the violator, 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, 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. Order 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. 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 oil pipelines regulated by FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 (“EPAct of 1992”), and the rules and regulations promulgated under those laws and, thus, have interstate tariffs on file with FERC setting forth our interstate transportation rates and charges and the rules and regulations applicable to our jurisdictional transportation service. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil, natural gas liquids and refined petroleum products pipelines, be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Under the ICA, shippers may challenge new or existing rates or services. FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. A successful rate challenge could result in an oil pipeline paying refunds for the period that the rate was in effect and/or reparations for up to two years prior to the filing of a complaint. FERC generally has not investigated oil pipeline rates on its own initiative.

Under the EPAct of 1992, oil 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 were not subject to complaint, protest or investigation during that 365-day period. These rates are commonly referred to as “grandfathered rates.” FERC may change grandfathered rates upon complaint only after it is shown that (i) a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate; (ii) the complainant was contractually barred from challenging the rate prior to enactment of the EPAct of 1992 and filed the complaint within 30 days of the expiration of the contractual bar; or (iii) a provision of the tariff is unduly discriminatory or preferential. The EPAct of 1992 places no similar limits on challenges to a provision of an oil pipeline tariff as unduly discriminatory or preferential.

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The EPAct of 1992 further required FERC to establish a simplified and generally applicable ratemaking methodology for interstate oil pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows oil pipelines to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, plus 2.65 percent. Rate increases made under the index are subject to protest, but the scope of the protest proceeding is limited to an inquiry into whether the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. The indexing methodology is applicable to any existing rate, including a grandfathered rate. Indexing includes the requirement that, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. However, the pipeline is not required to reduce its rates below the level deemed just and reasonable under the EPAct of 1992.

While an oil pipeline, as a general rule, must use the indexing methodology to change its rates, FERC also retained cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach. A pipeline can follow a cost-of-service approach when seeking to increase its rates above the rate ceiling (or when seeking to avoid lowering rates to the reduced rate ceiling), provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can charge market-based rates if it establishes that it lacks significant market power in the affected markets. In addition, a pipeline can establish rates under settlement.

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, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, 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. As a result of the recent bankruptcy of ATP Oil and Gas, the BOEM has indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators and may increase the amount of financial assurance required with respect to these obligations. Under certain circumstances, the 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. We own certain crude oil pipelines located on the OCS. BSEE regulates terms of service on OCS pipelines to provide open and nondiscriminatory access.

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. Although FERC has not made any formal determinations with respect to any of the natural gas gathering pipeline facilities that we own, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities, however, has been the subject of substantial litigation and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the

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other, is a fact-based determination made by FERC on a case-by-case basis. 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. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. 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 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

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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.

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.

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Employees

We had 271 employees at June 30, 2013. At June 30, 2013, 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, as amended, (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

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

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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 February 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.

Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. For instance, on June 5, 2013, our interest in the Lafitte well effectively expired due to the need for a completion process that would have required the development of 30,000 psi equipment. The design development and procurement of such equipment would require an extended period of time leading up to the initiation of completion activities.

Our drilling plans for areas not currently held by production are subject to change based upon various factors, including factors that are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. On our acreage that we do not operate, we have less control over the timing of drilling and there is therefore additional risk of expirations occurring in those sections.

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.

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Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. For example, the WTI crude oil spot price per barrel for the period between January 1, 2013 and June 30, 2013 ranged from a high of $98.44 to a low of $86.68 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2013 to June 30, 2013 ranged from a high of $4.41 to a low of $3.11. 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;

• 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.

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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, 2013 prepared in a manner consistent with our interpretation of the SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies, as well as the interpretation of our independent petroleum consultant performing an audit of our reserve estimates. 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, 2013, we reduced our proved reserve estimates by 1.4 MMBOE due to the five year development rule.

As of June 30, 2013, approximately 39% of our total proved reserves were undeveloped and approximately 10% 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 3% of our proved undeveloped reserves, so we may not be in a position to control the timing of all development activities. Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reserves will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.

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

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 U.S. Typically, 50% of the reserves of properties in the U.S. Gulf of Mexico are depleted within three to four years with natural gas wells having a higher rate of depletion than oil wells. 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.

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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 eight wells to date with our participations ranging from approximately 9% to 20%. These projects have similar geological characteristics as deepwater prospects with a potential for significant reserves. The 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 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

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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 severe, 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.

Weather Based Insurance Linked Securities may not payout in case of a hurricane or may not fully cover damage.

We utilize Weather Based Insurance Linked Securities (“Securities”) to supplement our windstorm insurance coverage to mitigate potential loss to our most valuable oil and gas properties from hurricanes in the Gulf of Mexico. These Securities are generally structured to provide for payments of negotiated amounts should a hurricane having a pre-established category pass within specific pre-defined areas encompassing our oil and gas producing fields. If the criteria are met, the payout is made to us irrespective of whether there is any actual damage. While these Securities are meant to provide some excess windstorm coverage, there can be no certainty that these Securities will meet the payout criteria even if there is substantial damage by a hurricane of a lower category than that specified in the Securities. In addition, the payment made may not be sufficient to cover any actual damage incurred from a storm.

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 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;

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• 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 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.

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

As we carry out our planned drilling program, we will not serve as operator of all planned wells. We currently operate approximately 94% 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. From time to time, the availability of credit is more restrictive. 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 35%, ExxonMobil accounted for approximately 37% and J.P. Morgan accounted for approximately 12% of our total oil and natural gas revenues during the year ended June 30, 2013. Our inability to continue to sell our production to Shell, ExxonMobil 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 referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated or the decommissioning be accelerated, such as can happen after a hurricane, such costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations.

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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 of 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.

Cyber incidents could result in information theft, data corruption, operational disruption, and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation, and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as power generation and transmission, communications and oil and gas pipelines.

We depend on digital technology, including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The complexity of the technologies needed to extract oil and gas in increasingly difficult physical environments, such as ultra-deep trend, and global competition for oil and gas resources make certain information more attractive to thieves.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. Certain countries, including China, Russia and Iran, are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies. SCADA-based systems are potentially more vulnerable to cyber attacks due to the increased number of connections with office networks and the internet.

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Our technologies, systems, networks, and those of our business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:

• unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

• data corruption, communication interruption, or other operational disruption during drilling activities could result in a dry hole cost or even drilling incidents;

• data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;

• a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt one of our major development projects, effectively delaying the start of cash flows from the project;

• a cyber attack on a third party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenues;

• a cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;

• a cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues;

• a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

• a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

• business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.

Although to date we have not experienced any losses relating to cyber attacks, there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

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.

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

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

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

• 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 U.S. 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;

• increasing our indebtedness; and

• incurring 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.

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

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

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

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

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

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 our financial position and results of operations.

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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, 2013, we had total indebtedness of $1,370 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;

• 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, 2013, we and our subsidiary guarantors collectively had approximately $365 million of secured indebtedness and $1 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

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• 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 contain various covenants that limit our ability and the ability of our subsidiaries to, among other things:

• incur dividend or other payment obligations;

• incur indebtedness and issue preferred stock; and

• 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.

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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, 2013, we had borrowed $339 million and had $225 million in letters of credit issued under our revolving credit facility and our borrowing base was $850 million. We expect that the next determination of the borrowing base under our revolving credit facility will occur in the fall of 2013. 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 in their sole discretion. The lenders will redetermine the borrowing base based on an engineering report with respect to our natural gas and oil reserves, which will take into account the prevailing natural gas and oil prices at such time. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (1) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (2) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. If oil and natural gas commodity prices deteriorate, the revised borrowing base under our revolving credit facility may be reduced. As a result, we may be unable to obtain adequate funding under our revolving credit facility or even be required to pay down amounts outstanding under our revolving credit facility to reduce our level of borrowing. If funding is not available when needed, or is available only on unfavorable terms, it could adversely affect our exploration and development plans as currently anticipated and our ability to make new acquisitions, each of which could have a material adverse effect on our production, revenues and results of operations.

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.

With the increase in our proved reserves as of June 30, 2013 versus June 30, 2012, we intend to seek an increase in the borrowing base as part of our next redetermination to occur as scheduled in the fall of 2013.

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

The recent credit crisis and related turmoil in the global financial systems had an impact on our business and our financial condition, and we may face challenges if economic and financial market conditions deteriorate in the future. Historically, we have used our cash flow from operations and borrowings under our revolving credit facility to fund our capital expenditures and have relied on the capital markets to provide us with additional capital for large or exceptional transactions. A recurrence of the economic crisis could further reduce the demand for oil and natural gas and put downward pressure on the prices for oil and natural gas.

Our current borrowing base under our revolving credit facility is $850 million. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (1) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (2) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Declines in commodity prices, or a continuing decline in those prices, could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The turmoil in the financial markets has adversely impacted the stability and solvency of a number of large global financial institutions.

The recent credit crisis 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

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of obtaining financing 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.

As described in more detail below, our business activities are subject to regulation by multiple federal, state and local governmental agencies. Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues. Additional proposals and proceedings that affect the oil and gas industries are regularly considered by Congress, the states, regulatory commissions and agencies, and the courts. We cannot predict when or whether any such proposals may become effective or the magnitude of the impact changes in laws and regulations may have on our business; however, additions or enhancements to the regulatory burden on our industry generally increase the cost of doing business and affect our profitability.

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

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

FERC regulates interstate natural gas transportation rates and terms of service, 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 methodology for interstate 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

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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.

Although FERC has not made any formal determinations with respect to any of our facilities, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine if a pipeline is a gathering pipeline and are therefore not subject to FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation, however, and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by FERC on a case-by-case basis. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act of 1978 (NGPA). Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by FERC.

State regulation of gathering facilities includes 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. State and local regulation may cause us to incur additional costs or limit our operations and 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. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.

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 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.

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

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.

Rate regulation may not allow us to recover the full amount of increases in our costs.

We have ownership interests in oil pipelines that are subject to regulation by FERC. Rates for service on our system are set using FERC’s price indexing methodology. The indexing method currently allows a pipeline to increase its rates by a percentage factor equal to the change in the producer price index for finished goods plus 2.65 percent. When the index falls, we are required to reduce rates if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs.

FERC’s indexing methodology is subject to review every five years. The current or any revised indexing formula could hamper our ability to recover our costs because: (1) the indexing methodology is tied to an inflation index; (2) it is not based on pipeline-specific costs; and (3) it could be reduced in comparison to the current formula. Any of the foregoing would adversely affect our revenues and cash flow. FERC could limit our pipeline’s ability to set rates based on its costs, order our pipelines to reduce rates, require the payment of refunds or reparations to shippers, or any or all of these actions, which could adversely affect our financial position, cash flows, and results of operations. If FERC’s ratemaking methodology changes, the new methodology could also result in tariffs that generate lower revenues and cash flow.

Based on the way our oil pipelines are operated, we believe that the only transportation on our pipelines that is subject to the jurisdiction of FERC is the transportation specified in the tariff we have on file with FERC. We cannot guarantee that the jurisdictional status of transportation on our pipelines and related facilities will remain unchanged, however. Should circumstances change, then currently non-jurisdictional transportation could be found to be FERC-jurisdictional. In that case, FERC’s ratemaking methodologies may limit our ability to set rates based on our actual costs, may delay the use of rates that reflect increased costs, and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, results of operations and financial condition.

If our tariff rates are successfully challenged, we could be required to reduce our tariff rates, which would reduce our revenues.

Shippers on our pipelines are free to challenge, or to cause other parties to challenge or assist others in challenging, our existing or proposed tariff rates. If any party successfully challenges our tariff rates, the effect would be to reduce revenues.

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 April 2010 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. 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. The Workplace Safety Rule also has the potential to increase the cost of operating existing wells.

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

FERC, the FTC and the CFTC hold statutory authority to regulate 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 commodities, we are required to observe and comply with these anti-fraud and anti-manipulation regulations. 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 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.

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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 Dodd-Frank 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.

We 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 Ocean 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, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. As a result of the recent bankruptcy of ATP Oil and Gas, the BOEM has indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators and may increase the amount of financial assurance required with respect to these obligations. 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

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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 2014 sent to Congress by President Obama on April 10, 2013, 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.

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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 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 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
Fiscal 2013
First Quarter		37.37		29.76
Second Quarter		35.60		30.68
Third Quarter		34.83		27.16
Fourth Quarter		26.79		21.78

As of July 31, 2013, there were approximately 374 holders of record of our unrestricted common stock.

Dividend Information

We paid quarterly cash dividends of $0.07 per share to holders of our common stock on September 14, 2012, December 14, 2012 and March 15, 2013 to shareholders of record on August 31, 2012, November 30, 2012 and March 1, 2013, respectively.

We paid quarterly cash dividends of $0.12 per share to holders of our common stock on June 14, 2013, to shareholders of record on May 31, 2013.

On July 17, 2013, our Board of Directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of our common stock. The quarterly dividend will be paid on September 13, 2013 to shareholders of record on August 30, 2013.

Purchases of Equity Securities

Repurchases of Common Stock

In May 2013, our Board of Directors approved a stock repurchase program authorizing us to repurchase up to $250 million in value of our common stock for an extended period of time, in one or more open market transactions. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity and other appropriate factors. The repurchase program does not obligate us to acquire any particular amount of common stock and may be modified or suspended at any time and could be terminated prior to completion. The repurchase program will be funded with cash on hand or borrowings under our revolving credit facility. Any repurchased shares of common stock will be retained at the subsidiary level, subject to transfer to the parent company where they may be retired.

In connection with the repurchase program, our Board of Directors also approved a Rule 10b5-1 plan that allows us to repurchase common stock at times when it otherwise might be prevented from doing so under insider trading laws or because of self-imposed trading blackout periods. A broker selected by us has the authority under the pricing parameters and other terms and limitations specified in the 10b5-1 plan to repurchase shares on our behalf. We periodically report the number of shares purchased under the plan.

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The following table presents information about repurchases of our common stock during the quarter ended June 30, 2013:

Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs
							(In millions)
May 1, 2013 through May 31, 2013		2,047,000	$	25.23		2,047,000	$	198.3
June 1, 2013 through June 30, 2013		891,900	$	23.49		891,900	$	177.3
Total		2,938,900	$	24.70		2,938,900

In July 2013, we utilized a total of $21.2 million to repurchase 914,000 shares of our common stock at a weighted average price per share, excluding fees, of $23.19, after which, $156.1 million remains available for repurchase under the share repurchase program.

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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,
	2013			2012			2011			2010			2009
	(In Thousands, Except per Share Amounts)
Income Statement Data
Revenues	$	1,208,845		$	1,303,403		$	859,370		$	498,931		$	433,830
Depreciation, Depletion and Amortization (“DD&A”)		376,224			367,463			293,479			181,640			217,207
Impairment of Oil and Gas Properties		—			—			—			—			576,996
Operating Income (Loss)		361,805			483,284			208,923			102,047			(517,217	)
Other Income (Expense) – Net		(113,091	)		(108,811	)		(132,006	)		(58,483	)		(76,751	)
Net Income (Loss)		162,081			335,827			64,655			27,320			(571,629	)
Basic Earnings (Loss) per Common Share	$	1.90		$	4.10		$	0.42		$	0.56		$	(19.77	)
Diluted Earnings (Loss) per Common Share	$	1.86		$	3.85		$	0.42		$	0.56		$	(19.77	)
Cash Flow Data
Provided by (Used in)
Operating Activities	$	638,148		$	785,514		$	387,725		$	121,213		$	245,835
Investing Activities
Acquisitions		(161,164	)		(6,401	)		(1,012,262	)		(293,037	)		—
Investment in properties		(816,105	)		(570,670	)		(281,233	)		(145,112	)		(266,012	)
Other		(16,734	)		7,478			38,423			53,989			2,935
Total Investing Activities		(994,003	)		(569,593	)		(1,255,072	)		(384,160	)		(263,077	)
Financing Activities		238,768			(127,241	)		881,530			188,246			(62,795	)
Increase (Decrease) in Cash	$	(117,087	)	$	88,680		$	14,183		$	(74,701	)	$	(80,037	)
Dividends Paid per Average Common Share	$	0.0825		$	0.07			—			—		$	0.075

	June 30,
	2013		2012		2011		2010		2009
	(In Thousands)
Balance Sheet Data
Total Assets	$	3,611,711	$	3,130,947	$	2,798,860	$	1,566,491	$	1,328,662
Long-term Debt Including Current Maturities		1,370,045		1,018,344		1,113,387		774,600		862,827
Stockholders’ Equity		1,437,246		1,405,840		946,697		436,561		127,500
Common Shares Outstanding		76,486		78,838		76,203		50,637		29,150

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	Year Ended June 30,
Operating Highlights	2013			2012			2011			2010			2009
	(In Thousands, Except per Unit Amounts)
Operating revenues
Crude oil sales	$	1,067,686		$	1,186,193		$	777,869		$	383,928		$	278,014
Natural gas sales		112,753			88,608			101,815			69,399			113,156
Hedge gain (loss)		28,406			28,602			(20,314	)		45,604			42,660
Total revenues		1,208,845			1,303,403			859,370			498,931			433,830
Percent of operating revenues from crude oil
Prior to hedge gain (loss)		90	%		93	%		88	%		85	%		71	%
Including hedge gain (loss)		89	%		91	%		84	%		78	%		68	%
Operating expenses
Lease operating expense
Insurance expense		32,737			28,521			27,876			27,603			19,188
Workover and maintenance		65,118			56,413			33,095			19,630			15,930
Direct lease operating expense		239,308			225,881			178,507			95,379			87,032
Total lease operating expense		337,163			310,815			239,478			142,612			122,150
Production taxes		5,246			7,261			3,336			4,217			5,450
Gathering and transportation		24,168			16,371			12,499			—			—
Depreciation, depletion and amortization		376,224			367,463			293,479			181,640			217,207
Impairment of oil and gas properties		—			—			—			—			576,996
General and administrative		71,598			86,276			75,091			49,667			24,756
Other – net		32,641			31,933			26,564			18,748			4,488
Total operating expenses		847,040			820,119			650,447			396,884			951,047
Operating income (loss)	$	361,805		$	483,284		$	208,923		$	102,047		$	(517,217	)
Sales volumes per day
Natural gas (MMcf)		88.6			81.5			67.2			42.6			47.9
Crude oil (MBbls)		28.3			30.5			23.4			14.7			11.4
Total (MBOE)		43.1			44.1			34.6			21.8			19.3
Percent of sales volumes from crude oil		66	%		69	%		68	%		67	%		59	%
Average sales price
Natural gas per Mcf	$	3.48		$	2.97		$	4.15		$	4.47		$	6.48
Hedge gain per Mcf		0.47			0.94			1.54			2.68			1.60
Total natural gas per Mcf	$	3.95		$	3.91		$	5.69		$	7.15		$	8.08
Crude oil per Bbl	$	103.48		$	106.17		$	90.95		$	71.73		$	67.06
Hedge gain (loss) per Bbl		1.29			0.04			(6.80	)		0.75			3.56
Total crude oil per Bbl	$	104.77		$	106.21		$	84.15		$	72.48		$	70.62
Total hedge gain (loss) per BOE	$	1.81		$	1.77		$	(1.61	)	$	5.74		$	6.04
Operating revenues per BOE	$	76.95		$	80.74		$	67.98		$	62.83		$	61.47
Operating expenses per BOE
Lease operating expense
Insurance expense		2.08			1.77			2.21			3.48			2.72
Workover and maintenance		4.15			3.49			2.62			2.47			2.26
Direct lease operating expense		15.23			13.99			14.12			12.01			12.33
Total lease operating expense per BOE		21.46			19.25			18.95			17.96			17.31
Production taxes		0.33			0.45			0.26			0.53			0.77
Impairment of oil and gas properties		—			—			—			—			81.75
Gathering and transportation		1.54			1.01			0.98			—			—
Depreciation, depletion and amortization		23.95			22.76			23.22			22.87			30.78
General and administrative		4.56			5.34			5.94			6.25			3.51
Other – net		2.08			1.98			2.10			2.36			0.64
Total operating expenses per BOE		53.92			50.79			51.45			49.97			134.76
Operating income (loss) per BOE	$	23.03		$	29.95		$	16.53		$	12.86		$	(73.29	)

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	Quarter Ended
Operating Highlights	June 30, 2013			Mar. 31, 2013			Dec. 31, 2012			Sept. 30, 2012			June 30, 2012
	(In Thousands, Except per Unit Amounts)
Operating revenues
Crude oil sales	$	270,623		$	273,280		$	280,953		$	242,830		$	314,639
Natural gas sales		38,630			27,070			29,657			17,396			19,657
Hedge gain		5,072			3,424			9,909			10,001			7,650
Total revenues		314,325			303,774			320,519			270,227			341,946
Percent of operating revenues from crude oil
Prior to hedge gain		88	%		91	%		90	%		93	%		94	%
Including hedge gain		87	%		90	%		89	%		92	%		92	%
Operating expenses
Lease operating expense
Insurance expense		7,462			7,473			8,810			8,992			6,825
Workover and maintenance		15,622			19,166			20,217			10,113			21,070
Direct lease operating expense		59,371			59,666			56,895			63,376			59,306
Total lease operating expense		82,455			86,305			85,922			82,481			87,201
Production taxes		1,481			1,352			1,166			1,247			2,414
Gathering and transportation		5,668			4,411			6,098			7,991			4,358
DD&A		96,846			88,727			105,856			84,795			106,644
General and administrative		12,299			16,092			19,319			23,888			19,733
Other – net		3,829			7,017			8,621			13,174			5,186
Total operating expenses		202,578			203,904			226,982			213,576			225,536
Operating income	$	111,747		$	99,870		$	93,537		$	56,651		$	116,410
Sales volumes per day
Natural gas (MMcf)		107.4			89.4			90.9			67.1			92.5
Crude oil (MBbls)		28.9			28.6			29.4			26.1			32.2
Total (MBOE)		46.8			43.5			44.6			37.3			47.6
Percent of sales volumes from crude oil		62	%		66	%		66	%		70	%		68	%
Average sales price
Natural gas per Mcf	$	3.95		$	3.37		$	3.55		$	2.82		$	2.34
Hedge gain per Mcf		0.23			0.29			0.60			0.89			0.55
Total natural gas per Mcf	$	4.18		$	3.66		$	4.15		$	3.71		$	2.89
Crude oil per Bbl	$	102.82		$	106.11		$	103.79		$	101.03		$	107.34
Hedge gain per Bbl		1.08			0.42			1.80			1.87			1.03
Total crude oil per Bbl	$	103.90		$	106.53		$	105.59		$	102.90		$	108.37
Total hedge gain per BOE	$	1.19		$	0.87		$	2.42		$	2.91		$	1.77
Operating revenues per BOE	$	73.78		$	77.58		$	78.15		$	78.72		$	78.90
Operating expenses per BOE
Lease operating expense
Insurance expense		1.75			1.91			2.15			2.62			1.57
Workover and maintenance		3.67			4.89			4.93			2.95			4.86
Direct lease operating expense		13.94			15.24			13.87			18.46			13.68
Total lease operating expense per BOE		19.36			22.04			20.95			24.03			20.11
Production taxes		0.35			0.35			0.28			0.36			0.56
Gathering and transportation		1.33			1.13			1.49			2.33			1.01
DD&A		22.73			22.66			25.81			24.70			24.61
General and administrative		2.89			4.11			4.71			6.96			4.55
Other – net		0.90			1.79			2.10			3.84			1.20
Total operating expenses per BOE		47.56			52.08			55.34			62.22			52.04
Operating income per BOE	$	26.22		$	25.50		$	22.81		$	16.50		$	26.86

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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” in this Form 10-K.

General

We are an independent oil and natural gas exploration and production company with operations focused in the U.S. Gulf Coast and the Gulf of Mexico. Our business strategy includes: (1) acquiring producing oil and gas properties; (2) exploiting and exploring our core assets to enhance production and ultimate recovery of reserves; and (3) utilizing a portion of our capital program to explore the ultra-deep shelf for potential oil and gas reserves.

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, 2013, excluding acquisitions, approximately 50% of our capital expenditures were associated with the exploitation of existing properties.

At June 30, 2013, our total proved reserves were 178.5 MMBOE of which 75% were oil and 61% were classified as proved developed. We operated or had an interest in 463 gross producing wells on 272,262 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 93% 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 94% of our proved reserves are on properties operated by us. We have a seismic database covering approximately 7,460 square miles, primarily focused on our existing operations. This database has helped us identify approximately 243 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.

Fiscal Year 2013

Acquisitions

ExxonMobil oil and gas properties interests acquisition

On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“Exxon”) for a total cash consideration of approximately $32.8 million. The GOM Interests cover 5,000 gross acres on Vermilion Block 164 (“VR 164”). We are the operator of these properties. In addition to acquiring the GOM Interests, we entered into a joint venture agreement with Exxon to explore for oil and gas on nine contiguous blocks adjacent to VR 164 in shallow waters on the GOM shelf. We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012.

Dynamic Offshore oil and gas properties interests acquisition

On November 7, 2012, we acquired 100% of the interests (“Dynamic Interests”) held by Dynamic Offshore Resources, LLC (“Dynamic”) on VR 164 for approximately $7.2 million.

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McMoRan oil and gas properties interests acquisition

On January 17, 2013, we closed on the acquisition of certain onshore Louisiana interests in the Bayou Carlin field (“Bayou Carlin Interests”) from McMoRan Oil and Gas, LLC (“McMoRan”) for a total cash consideration of $79.3 million. This acquisition is effective January 1, 2013. We are the operator of these properties.

RoDa oil and gas properties interests acquisition

On March 14, 2013, we acquired 100% of the interests (“RoDa Interests”) held by RoDa Drilling LP (“RoDa”) in the Bayou Carlin field for $32.7 million. This acquisition is effective January 1, 2013.

Tammany oil and gas properties interests acquisition

On June 28, 2013, we closed on the acquisition of certain offshore Louisiana interests in the West Delta field (“West Delta Interests”) from Tammany Energy Ventures, LLC (“Tammany”) for a total cash consideration of $8.3 million. This acquisition is effective June 1, 2013. We will be the operator of these properties.

Apache Joint Venture

On February 1, 2013, we entered into an Exploration Agreement (“Agreement”) with Apache Corporation (“Apache”) to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central Gulf of Mexico Shelf. We have a 25% participation interest in the Agreement, which expires on February 1, 2018.

The area of mutual interest under this agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million of which approximately $17.9 million was incurred through June 30, 2013. We have presently consented to participate in drilling one well and have an option to participate in two other wells under the current drilling program. Drilling on the first well commenced in May 2013 and our share of the costs related to this well at June 30, 2013 were approximately $8.1 million.

As of June 30, 2013, we paid consideration of approximately $3 million, being our participation interest, to Apache for 21 non-producing primary-term leases.

Please see Note 3 — “Acquisitions and Dispositions” to our Consolidated Financial Statements in this Form 10-K for more information regarding these transactions.

Ultra-Deep Trend Exploration and Development Activity

We participate with Freeport McMoRan and Chevron U.S.A. Inc. in several prospects in the ultra-deep shelf and onshore area (“ultra-deep trend”) in the Gulf of Mexico. Data received to date from ultra-deep trend drilling with respect to the Davy Jones and Blackbeard West discovery wells in the Gulf of Mexico confirm geologic modeling that correlates objective sections on the shelf below the salt weld in the Miocene and older age sections to those productive sections seen in deepwater discoveries by other industry participants. In addition to Davy Jones and Blackbeard West, the Freeport McMoRan operated group has also identified approximately 20 ultra-deep prospects near existing infrastructure. Since 2008, the Ultra-Deep drilling program has included Blackbeard East, Lafitte, Blackbeard West, Lomond North, Blackbeard West No. 2 and Lineham Creek exploratory wells and delineation drilling at Davy Jones. We expect to have more than sufficient liquidity to fund our current commitments related to our ultra-deep trend exploration and development activity.

As previously reported, we have drilled two successful salt wells in the Davy Jones field. The Davy Jones No. 1, drilled to a true vertical depth 28,977 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, true vertical depth 30,422), 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. The Davy Jones field involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). As of June 30, 2013, our investment in both wells in the Davy Jones field totaled approximately $147 million.

49

Davy Jones.  The Davy Jones No. 1 well on South Marsh Island Block 230 in 19 feet of water 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 Freeport McMoRan operated group from obtaining a measurable flow rate. In January 2013, the operator re-perforated the Wilcox zones in the well with through-tubing perforating guns. Operations confirm that the perforations were open and that fluid could be injected through the perforations into the formation. A mini hydraulic fractured was performed indicating that the well could be fracture stimulated.

Blackbeard East.  The Blackbeard East ultra-deep exploration by-pass well located in 80 feet of water on South Timbalier Block 144 was drilled to a true vertical 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 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 held the lease rights to South Timbalier Block 144 through August 17, 2012 and prior to the lease expiration date, submitted initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement (“BSEE”). The operator plans to test and complete the upper Miocene sands during 2014 using 20,000 psi equipment and conventional technologies. Additional plans for further development of the deeper zones continue to be evaluated. The Freeport McMoRan operated group’s ability to preserve the interest in Blackbeard East will require approval from the BSEE of the development plans. As of June 30, 2013, our investment in the well totaled approximately $51 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 true vertical 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, Upper Eocene, and Sparta carbonate. Freeport McMoRan's lease rights to Eugene Island Block 223 expired on October 8, 2012. Prior to the lease expiration, the operator submitted its initial development plans to complete and test the Frio/Cris R sands in the upper Eocene for Lafitte to the BSEE. This completion would have required the development of 30,000 psi equipment and the design development and procurement of such equipment would require an extended period of time leading up to the initiation of completion activities. For business reasons, in June 2013 the operator withdrew its Suspension of Production application requesting no further action from BSEE. As a result, our interest in the Lafitte well and related leases effectively expired. As of June 30, 2013, 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 drilled in 70 feet of water on South Timbalier Block 168 was drilled to measured depth of 32,997 feet in 2008. Logs indicated four potential hydrocarbon bearing zones that require further evaluation. The well was temporarily abandoned.

The Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal 188 commenced drilling in 70 feet of water on November 25, 2011 and reached true vertical depth of 25,584 feet in January 2013. Through logs and core data, the operator has identified three potential hydrocarbon bearing Miocene sand sections between approximately 20,900 and 24,000 feet. Initial completion efforts are expected to focus on the development of approximately 50 net feet of laminated sands in the Middle Miocene located at approximately 24,000 feet. Additional development opportunities in the well bore include approximately 80 net feet of potential low-resistivity pay at approximately 22,400 feet and an approximate 75 foot gross section at approximately 20,900 feet. Pressure and temperature data indicate that a completion at these depths could utilize conventional equipment and conventional technologies. Our investment in both Blackbeard West wells totaled approximately $57 million at June 30, 2013. Our operating partner’s current plans are to complete the well using 20,000 psi equipment and technologies in late 2013 or early 2014.

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Lineham Creek.  The Lineham Creek ultra deep exploration well, operated by Chevron U.S.A. Inc., which is located onshore in Cameron Parish, Louisiana commenced drilling on March 31, 2011. The well, which targets Eocene and Paleocene objectives below the salt weld was drilled to a total depth of 29,426 feet true vertical depth before sticking and the drill pipe was unable to be recovered. The proposed total drilling depth was 30,500 feet. The well encountered positive results in the Yegua sands section in November 2012. Detailed whole core and log data obtained will be used in evaluating future plans for all ultra-deep wells. The well is currently being sidetracked at 23,000 feet, and we expect the well to be drilled to 24,600 feet of true vertical depth in order to collect conventional cores from the Yegua sands section. As of June 30, 2013, our investment in the Lineham Creek well totaled approximately $17 million.

Lomond North.  The Lomond North exploration prospect located onshore in St. Martin Parish, Louisiana, commenced drilling on September 19, 2012 in the Highlander area where multiple high potential prospects on an 80,000 acre position have been identified and is operated by Freeport McMoRan. The well which is targeting Eocene, Creataceous and Paleocene objectives below the salt weld, is currently drilling below 25,100 feet towards a proposed total depth of 30,000 feet. As of June 30, 2013, our investment in the Lomond North well totaled approximately $21 million. Completion design and planning is underway for long lead time items.

Outlook

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. Multiple events during 2009 through 2013 involving numerous countries and financial institutions and the market, in general, impacted liquidity within the capital markets. While 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 have improved the capital markets, there is no assurance there will not be another shock to the capital and credit markets that could constrain credit. As a result, we expect that our ability to raise debt and equity and the terms on which we can raise capital could become somewhat restricted and will be dependent upon the condition of the capital and credit markets.

Although we currently expect to fund our capital program from existing cash flow from operations, these cash flows are dependent upon future production volumes and commodity prices. Maintaining adequate liquidity may involve the issuance of additional debt and equity at less attractive terms, could involve the sale of assets and could require reductions in our capital spending. In the near-term we will focus on maximizing returns on existing assets by deploying capital to improve existing production, pursuing our ultra-deep trend exploration program and our Apache and ExxonMobil joint venture program. Approximately 50 percent of our $660 million fiscal 2014 capital budget is focused on development of our core properties, 19 percent is on exploration and 12 percent is on facilities.

Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. As required by our revolving credit facility, we have mitigated this volatility through December 2015 by implementing a hedging program on a portion of our total anticipated production during this time frame. See Note 9 Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Form 10-K for a detailed discussion of our hedging program.

We are also subject to natural gas and oil production declines in our producing properties. We attempt to replace this declining production through our drilling and recompletion program and acquisitions. We will maintain our focus on controlling costs to add reserves through drilling and acquisitions, as well as controlling the corresponding costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability to timely obtain drilling permits and regulatory approvals and voluntary reductions in capital spending in a low commodity price environment as is currently being experienced in the natural gas market. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of our production, which may have an adverse effect on our revenues. Consistent with our business strategy, we intend to invest the capital necessary to maintain our production at existing levels over the long-term provided

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that it is economical to do so based on the commodity price environment. However, we cannot be certain that we will be able to issue additional debt and equity on acceptable terms, or at all, and we may be unable to refinance our revolving credit facility when it expires on April 9, 2018. Additionally, should commodity prices decline, our borrowing base under our revolving credit facility may be reduced thereby eliminating the working capital necessary to fund our capital spending program as well as potentially requiring us to repay certain of our outstanding indebtedness. With the increase in our proved reserves as of June 30, 2013 versus June 30, 2012, we intend to seek an increase in the borrowing base as part of our next redetermination to occur as scheduled in the fall of 2013.

Known Trends and Uncertainties

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 Gulf of Mexico 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.

Exploring New Salt Plays.  Using a portion of our exploration budget, we explore for reserves in emerging plays beneath salt and in the shadow of salt, where seismic imaging can be difficult, but large structures with world-class resource potential exist. This includes salt-shadow joint ventures with Apache Corporation (“Apache JV”) in the Main Pass Area and with ExxonMobil in Vermillion Block 164 and 179, as well as the ultra-deep trend (depths in excess of 25,000 feet, either onshore or in water depths of less than 150 feet). Since 2008, we have partnered with Freeport McMoRan Oil and Gas, LLC (formerly McMoRan Exploration Company and now acquired by Freeport McMoRan Copper and Gold, Inc.) (“Freeport McMoRan”) to explore the ultra-deep trend. Including the Davy Jones discovery well and Blackbeard West discovery well, the Freeport McMoRan operated group (in which we have various interests) has identified approximately 20 ultra-deep prospects near existing infrastructure. We have participated in 8 wells to date with our participations ranging from approximately 9% to 20%. In the ExxonMobil JV, the original Pendragon well encountered mechanical issues and was plugged and abandoned. Plans are to drill an offset well (Pendragon #2) and the Merlin prospect in fiscal 2014, making use of reprocessed 3D seismic data to improve imaging of the prospects. In the Apache JV we are employing WAZ seismic technology, one of the first ever on the Gulf of Mexico Shelf, to better image prospects. We are currently drilling the Heron prospect, with additional prospects expected to be drilled once we have analyzed the WAZ data and the Heron results. We target to spend less than 15% of our budgeted cash flow on our exploration activities on the salt plays.

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Results of Operations

Year Ended June 30, 2013 Compared With the Year Ended June 30, 2012

Our consolidated net income available for common stockholders was $150.6 million or $1.86 diluted per common share (“per share”) in fiscal 2013 as compared to consolidated net income available for common stockholders of $316.7 million or $3.85 diluted income per share in fiscal 2012. This decrease was primarily due lower crude oil sales prices and sales volumes coupled with higher costs and a higher effective income tax rate.

Sales Price and Volume Variances

	Year Ended June 30,						Increase (Decrease)						Increase (Decrease)
	2013			2012			Amount			Percent
													(In Thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)	$	104.77		$	106.21		$	(1.44	)		(1	)%	$	(14,858	)
Natural gas sales prices (per Mcf)	$	3.95			3.91			0.04			1	%		1,294
Total price variance														(13,564	)
Volume Variance
Crude oil sales volumes (MBbls)		10,318			11,172			(854	)		(8	)%		(90,791	)
Natural gas sales volumes (MMcf)		32,354			29,823			2,531			8	%		9,797
BOE sales volumes (MBOE)		15,710			16,143			(433	)		(3	)%
Percent of BOE from crude oil		66	%		69	%
Total volume variance														(80,994	)
Total price and volume variance													$	(94,558	)

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

Revenue Variances

	Year Ended June 30,				Increase (Decrease)
	2013		2012		Amount			Percent
			(In Thousands)
Crude oil	$	1,080,982	$	1,186,631	$	(105,649	)		(9	)%
Natural gas		127,863		116,772		11,091			9	%
Total revenues	$	1,208,845	$	1,303,403	$	(94,558	)		(7	)%

Oil and Natural Gas Revenues

Our consolidated revenues decreased $94.6 million in fiscal 2013. Lower revenues were primarily due to lower crude oil and sales volumes and sales prices partially offset by the impact of higher natural gas sales volumes and 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. Lower net commodity prices decreased revenues by $13.6 million in fiscal 2013. Average crude oil prices, including a $1.29 realized gain per barrel related to hedging activities, decreased $1.44 per barrel in fiscal 2013, resulting in decreased revenues of $14.9 million. Average natural gas prices, including a $0.47 realized gain per Mcf related to hedging activities, increased $0.04 per Mcf during fiscal 2013, resulting in increased revenues of $1.3 million. Commodity prices are affected by many factors that are outside of our control. Commodity prices we received during fiscal 2013 are not necessarily indicative of prices we may receive in

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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. Lower BOE sales volumes in fiscal 2013 resulted in decreased revenues of $81 million. Crude oil sales volumes decreased 854 MBbls in fiscal 2013, resulting in lower revenues of $90.8 million. The decrease in crude oil sales volumes in fiscal 2013 was principally due to the shut-in of production due to the damage caused by Hurricane Isaac and natural decline. Natural gas sales volumes increased 2,531 MMcf in fiscal 2013, resulting in improved revenues of $9.8 million. The increase in natural gas sales volumes in fiscal 2013 was primarily due to the results of our capital program partially offset by the shut-in of production due to the damage caused by Hurricane Isaac and natural decline.

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
	2013						2012
	Amount			Per BOE			Amount			Per BOE
	(In Thousands, except per unit amounts)
Costs and expenses
Lease operating expense
Insurance expense	$	32,737		$	2.08		$	28,521		$	1.77		$	4,216
Workover and maintenance		65,118			4.15			56,413			3.49			8,705
Direct lease operating expense		239,308			15.23			225,881			13.99			13,427
Total lease operating expense		337,163			21.46			310,815			19.25			26,348
Production taxes		5,246			0.33			7,261			0.45			(2,015	)
Gathering and transportation		24,168			1.54			16,371			1.01			7,797
DD&A		376,224			23.95			367,463			22.76			8,761
Accretion of asset retirement obligation		30,885			1.97			39,161			2.43			(8,276	)
General and administrative expense		71,598			4.56			86,276			5.34			(14,678	)
Loss (gain) on derivative financial instruments		1,756			0.11			(7,228	)		(0.45	)		8,984
Total costs and expenses	$	847,040		$	53.92		$	820,119		$	50.79		$	26,921
Other (income) expense
Loss from equity method investees	$	6,397		$	0.41		$	—		$	—		$	6,397
Other (income) expense – other		(1,965	)		(0.13	)		(71	)		—			(1,894	)
Interest expense		108,659			6.92			108,882			6.74			(223	)
Total other (income) expense	$	113,091		$	7.20		$	108,811		$	6.74		$	4,280

Costs and expenses increased $26.9 million in fiscal 2013. This increase in costs and expenses was due in part to higher production related expenses in fiscal 2013. Below is a discussion of costs and expenses.

Lease operating expense increased $26.3 million in fiscal 2013 compared to fiscal 2012. This increase was primarily due to higher direct lease operating and workover and maintenance expenses stemming from the increase in producing properties resulting from acquisitions and from our capital program.

Gathering and transportation expense increased $7.8 million in fiscal 2013 compared to fiscal 2012. This increase was primarily due to increased pipeline operations due to the acquisition of additional gathering lines.

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DD&A expense increased $8.8 million primarily due to a higher DD&A rate ($18.7 million) partially offset by lower equivalent production ($9.9) million.

Accretion of asset retirement obligations decreased $8.3 million primarily as a result of downward revisions and settlement of asset retirement obligations during fiscal 2013.

The decrease in gain on derivative financial instruments in fiscal 2013 compared to fiscal 2012 of $9 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 $2 million primarily as a result of lower onshore production in 2013.

General and administrative expense decreased $14.7 million in fiscal 2013 principally as a result of lower compensation expense related to Restricted and Performance Units due to our lower common stock price.

Other (income) expense increased $4.3 million in fiscal 2013 as compared to fiscal 2012 due to the loss from equity method investees of $6.4 million which was partially offset by interest income of $1.9 million.

Income Tax Expense

Income tax expense increased $48 million in fiscal 2013 compared to fiscal 2012. The effective income tax rate for fiscal 2013 increased from fiscal 2012 from 10% to 34.8%. The increase in the effective tax rate from fiscal year 2012 of 10% to 34.8% in 2013 is due to the tax effect of increased earnings from U.S. operations taxed at the U.S. statutory tax rate of 35% that were not offset by a release of a significant valuation allowance in fiscal 2013 as it was in fiscal 2012. The effect of the increase in the effective income tax rate in fiscal 2013 was partially offset by lower pre-tax income in fiscal 2013.

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.

Sales Price and Volume Variances

	Year Ended June 30,						Increase (Decrease)						Increase (Decrease)
	2012			2011			Amount			Percent
													(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.

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Revenue Variances

	Year Ended June 30,				Increase (Decrease)
	2012		2011		Amount			Percent
	(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.

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

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

Costs and expenses and other (income) expense

	Year Ended June 30,												Increase (Decrease) Amount
	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
Interest income	$	(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.

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

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.

Proved 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 our internal reservoir engineers and were audited by NSAI. 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.

	Year Ended June 30, 2013						Year Ended June 30, 2012
	Oil MMBbls		Natural Gas Bcf		MMBOE		Oil MMBbls		Natural Gas Bcf		MMBOE
Proved
Developed		80.2		175.6		109.5		63.3		110.4		81.7
Undeveloped		53.4		93.5		69.0		21.5		98.6		37.9
Total Proved		133.6		269.1		178.5		84.8		209.0		119.6

Our proved developed reserve estimates increased by 27.8 MMBOE or 34% to 109.5 MMBOE at June 30, 2013 from 81.7 MMBOE at June 30, 2012. The increase was primarily due to:

• Additions of 11.2 MMBOE from drilling, recompletions, and wells returned to production with major additions at South Timbalier 54: 2.9 MMBOE, Main Pass 61: 2.5 MMBOE, Grand Isle 16: 1.7 MMBOE, and West Delta 73: 1.2 MMBOE;

• Improved well performance of 22.3 MMBOE was realized with major upward revisions at West Delta 73: 9.4 MMBOE, South Timbalier 54: 6.2 MMBOE, South Pass 49: 4.4 MMBOE, and Main Pass 61: 1.3 MMBOE;

• Offset by a 1 MMBOE downward performance revision at Main Pass 73, and 15.7 MMBOE of production, and

• Acquisitions of 8.0 MMBOE at Bayou Carlin: 7.0 MMBOE and Vermilion 164: 1.0 MMBOE.

Our proved undeveloped reserve estimates increased by 31.1 MMBOE or 82% to 69.0 MMBOE at June 30, 2013 from 37.9 MMBOE at June 30, 2012. The increase was primarily due to:

• Additions of 36.3 MMBOE from identification of new proved undeveloped reserve locations were primarily at West Delta 73: 14.2 MMBOE, West Delta 30: 12.6 MMBOE, South Timbalier 54: 7 MMBOE, and Main Pass 61: 1.5 MMBOE;

• Acquisitions of 4.8 MMBOE at Vermilion 164: 3.3 MMBOE and West Delta 30: 1.5 MMBOE;

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• Offset by 3.2 MMBOE of proved undeveloped reserves as of June 30, 2012 reserve report, which were converted to proved developed reserves and revised upward by 5.8 MMBOE in fiscal 2013. This resulted in a total of 9.0 MMBOE being converted to proved developed reserves during fiscal 2013 with the majority of the horizontal conversions at West Delta 73: 8.3 MMBOE. These proved undeveloped reserves were booked as directional/vertical in fiscal 2012 but we opted to drill these locations as horizontals instead for higher production rates and ultimate recovery. The upward revision was a result of the higher realized initial production performance and higher estimated ultimate recovery from horizontals versus verticals, and

• 1.4 MMBOE of proved undeveloped reserves expired at South Timbalier 21: 0.4 MMBOE and South Pass 49: 1 MMBOE due to the five year development rule.

Two proved undeveloped reserve locations were not converted into proved developed reserves within the five year requirement and remain booked as proved undeveloped at June 30, 2013. Main Pass 61 OCS-G 16493 A-3 and Main Pass 73 B-19 ST are both proved undeveloped reserve locations to be sidetracked, but are still producing and cannot be drilled until the proved developed producing zone in each well depletes.

We expanded our internal effort on reserves evaluation, as we transitioned from third-party-evaluated to third-party-audited reserves. Our technical staff was increased by over 40%, many of whom were focused on field studies which identified a large number of new proved undeveloped reserve locations. These proved undeveloped reserve locations accounted for approximately 50% of our proved reserves increase. Our increased staffing level also enabled us to devote time to analyze and validate our proved developed reserves estimates utilizing multiple estimation techniques. As permitted under the existing guidance we employ techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. 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 internal reservoir engineers employed technologies on a by-well basis such as decline curve analysis (rate versus time, rate versus cumulative production, oil cut versus cumulative production and semi-log oil cut versus cumulative production) and where prudent, on a reservoir by-reservoir basis (material balance, volumetric analysis and analogy) that have been demonstrated to yield results with consistency and repeatability. Performance analysis including rate-time decline curves was utilized for reserve revisions to current wells and accounted for production techniques such as water flooding and gas-lifting that enhances and/or maintains production rates over time. Material balance methods were also employed for reserve revisions to current wells, incorporating production and pressure data to assist with reserve updates, particularly for wells and/or reservoirs with minimal production history and/or decline to-date. Further, in applying multiple techniques, we looked for consistency between methods rather than the highest or lowest result. We also used our knowledge of reservoir-specific drive mechanisms to identify which of the methods were most likely to be representative of the performance of the well. In some cases this gave lower reserves than rate-time, while in other cases it resulted in the same or higher reserves. On an average however, primarily due to the drive mechanisms in our reservoirs, higher reserves resulted from more appropriate selection of the reserves evaluation method.

We update and approve our long range plan on an annual basis, which includes our program to drill proved undeveloped locations. This plan is reflected in our reserve report at June 30, 2013 (the “June 30 Reserve Report”). We only recorded proved undeveloped reserves in our June 30 Reserve Report if they were scheduled to be developed within a five-year time horizon under the Company’s long range plan. We update our five year plan supporting our year-end fiscal results annually based upon long range criteria, including top value projects, maximization of present value and production volumes, drilling obligations, five year rule, and anticipated availability of certain rig types. However, the relative proportion of total proved undeveloped reserves that the Company develops over the next five years will not be uniform year to year, but will vary by year depending on several factors, including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells, and the inclusion of new acquisitions with associated proved undeveloped reserves.

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In fiscal 2013, we converted 8.4% of our proved undeveloped reserves included in our June 30, 2012 reserve report. As scheduled in our long range plan that is reflected in the June 30 Reserve Report and further reflected in our initial budget for fiscal 2014, we expect to convert approximately 15% of our proved undeveloped reserves during fiscal year 2014, 24% during fiscal year 2015, 27% during fiscal year 2016, 16% during fiscal year 2017 and 18% during fiscal year 2018.

Our drilling programs during fiscal 2013 also contributed to our reserves increases. At West Delta 73 our 29 MMBOE increase was largely attributable to the success of our horizontal-well program, along with some contribution due to our ongoing field study. At Main Pass 61, a 7 MMBOE reserves increase was realized in large part due to the fiscal 2013 drilling program, which demonstrated that portions of the reservoir were in communication that were not previously known to be, thus increasing the volume of reservoir from which hydrocarbons will be recovered.

Liquidity and Capital Resources

Overview

As of June 30, 2013, we had $1,350 million in outstanding 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.

Additionally, we recently utilized borrowings under our revolving credit facility to make repurchases of our common stock under the $250 million stock repurchase program authorized by our Board of Directors in May 2013.

During the year ended June 30, 2013, we completed the following transactions that have improved our liquidity position, which are discussed in further detail below:

On April 9, 2013, Energy XXI Gulf Coast, Inc., (“EGC”) entered into the Fourth Amendment (the “Fourth Amendment”) to the First Lien Credit Agreement. The Fourth Amendment includes the following: (a) extension of the maturity date to April 9, 2018 (b) increase of commitments under the First Lien Credit Agreement from $925 million to $1,700 million, (c) increase in the borrowing base to $850 million, (d) reduction of the ranges of applicable margins on all borrowing by 0.25% to 0.50%, (e) approval of an increase in the cash distribution basket under which EGC can make dividend payments on its preferred and common stock, from $17 million to $50 million per calendar year, (f) increase in the general basket of permitted unsecured indebtedness from $250 million to $750 million, subject to a reduction in the borrowing base of 25 percent of any unsecured indebtedness issued in excess of $250 million, and (g) approval of additional ability of an affiliated entity to reinsure the assets and operations of EGC and its subsidiaries.

On May 1, 2013, EGC entered into the Fifth Amendment (the “Fifth Amendment”) to the First Lien Credit Agreement. The Fifth Amendment provides changes and other modifications to the First Lien Credit Agreement to increase the ability of EGC to make dividends and other distributions to us and our subsidiaries. Under the Amendment, EGC now can make such dividends and other distributions in an amount of up to $350 million per calendar year to the extent that, following each distribution, EGC and its subsidiaries have

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available liquidity, in the form of cash and available borrowing capacity under the First Lien Credit Agreement, of the greater of $150 million or 15% of the borrowing base under the First Lien Credit Agreement. Further, the amendment limits the total aggregate distributions made by EGC to a maximum of $70 million plus 50% of the cumulative consolidated net income of EGC between October 1, 2010 and the most recently ended fiscal quarter, and requires that the making of any such dividend or other distributions must otherwise comply with all contractual restrictions and obligations applicable to EGC.

At June 30, 2013, we had $339 million in borrowings and $225 million in letters of credit issued under our First Lien Credit Agreement which had a borrowing base of $850 million due April 2018. The June 30, 2013 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.

We maintain approximately $3.9 million and $40.5 million in bonds issued to BOEM and third parties, respectively, to secure the plugging and abandonment of wells on the OCS of the Gulf of Mexico as well as the removal of platforms and related facilities, right of way, operator bond and for overweight permit.

Our initial fiscal 2014 capital budget, excluding any potential acquisition but including abandonment costs, is expected to be approximately $660 million ($630 million prior to plugging and abandonment costs) of which approximately 50 percent is focused on development of our core properties, 19 percent is on exploration and 12 percent is on facilities. 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, 2014. 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 2014 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 and borrowings under our credit facility were used primarily to fund exploration and development expenditures during fiscal 2013.

Cash Flows

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

	Year Ended June 30,
	2013			2012			2011
	(In thousands)
Net cash provided by operating activities	$	638,148		$	785,514		$	387,725
Net cash used in investing activities		(994,003	)		(569,593	)		(1,255,072	)
Net cash provided by (used in) financing activities		238,768			(127,241	)		881,530
Net increase (decrease) in cash and cash equivalents	$	(117,087	)	$	88,680		$	14,183

Operating Activities

Net cash provided by operating activities during the year ended June 30, 2013 was $638.1 million as compared to $785.5 million provided by operating activities during fiscal 2012. The decrease is due in part to lower net commodity prices and production volumes coupled with higher production costs. Fiscal 2012 also included higher proceeds from sale of derivatives. Changes in operating assets and liabilities increased $34.6 million during fiscal 2013 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

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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, 2013, our reserve replacement ratio, which is calculated by dividing acquisitions, discoveries, extensions of existing fields and revisions to proved reserves by total production, was 475%. 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 $977.3 million, $577.1 million and $1,293.5 million for the years ended June 30, 2013, 2012 and 2011, respectively. The increase in cash used in investing activities in comparing fiscal 2013 to fiscal 2012 was primarily due to higher acquisitions in 2013 and higher investments in properties during fiscal 2013.

Financing Activities

Cash provided by financing activities was $238.8 million for the year ended June 30, 2013 as compared to cash used in financing activities of $127.2 million for the year ended June 30, 2012. During the year ended June 30, 2013, total proceeds from issuance of common stock were $5.4 million. Purchases of the company’s common shares were $58.7 million under our share repurchase program and net proceeds from our First Lien Credit Agreement were $332.7 million. During the year ended June 30, 2012, total proceeds from the issuance of common and preferred stock were $9.8 million and net repayments of our First Lien Credit Agreement were $111.6 million.

2014 Capital Budget

Excluding any potential acquisitions but including abandonment costs, we currently anticipate an initial capital budget for fiscal year 2014 of approximately $660 million, of which approximately 50 percent is focused on development of our core properties, 19 percent is on exploration and 12 percent is on facilities. 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, 2013, we had $119 million availability for borrowing under our revolving credit facility. Our current borrowing base is $850 million. Our next borrowing base redetermination is scheduled for the fall of 2013 utilizing our June 30, 2013 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 through June 30, 2014. 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.

Available Credit

Credit markets have been constrained due to a lack of liquidity and confidence in a number of financial institutions during 2009 through the present. Investors have sought perceived safe investments in securities of the U. S. government rather than individual entities. We may experience difficulty accessing the long-term credit markets should conditions return to levels prevailing in 2009 and early 2010. Additionally, constraints in the credit markets may increase the rates we are charged for utilizing these 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, 2014. 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, as amended, has lender

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commitments of $1,700 million and matures on April 9, 2018. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. 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 allowed to pay us a limited amount of distributions, subject to certain terms and conditions.

On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement, which provided EGC the ability to make distributions to us for various purposes, subject to varying limitations depending on the purpose of the distribution. The ability of EGC to make dividends was subject to EGC meeting minimum liquidity and maximum revolver utilization thresholds, and were further limited to an aggregate cumulative amount equal to $70 million plus 50% of our cumulative Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter. The ability of EGC to make dividend payments to us was modified in subsequent amendments.

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; (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.

On October 19, 2012, EGC entered into the Third Amendment (the “Third Amendment”) to the First Lien Credit Agreement. The Third Amendment provides changes, supplements, and other modifications for information specific to the lenders under the First Lien Credit Agreement and increased the borrowing base to $825 million.

On April 9, 2013, EGC entered into the Fourth Amendment to the First Lien Credit Agreement. The Fourth Amendment included the following revisions: (a) extension of the maturity date to April 9, 2018 (b) increase of commitments under the First Lien Credit Agreement from $925 million to $1,700 million, (c) increase in the borrowing base to $850 million, (d) reduction of the ranges of applicable margins on all borrowing by 0.25% to 0.50%, (e) approval of an increase in the cash distribution basket under which EGC can make dividend payments on its preferred and common stock, from $17 million to $50 million per calendar year, (f) increase in the general basket of permitted unsecured indebtedness from $250 million to $750 million, subject to a reduction in the borrowing base of 25 percent of any unsecured indebtedness issued in excess of $250 million, and (g) approval of additional ability of an affiliated entity to reinsure the assets and operations of EGC and its subsidiaries.

On May 1, 2013, EGC entered into the Fifth Amendment to the First Lien Credit Agreement. The Fifth Amendment provides changes and other modifications to the First Lien Credit Agreement to increase the ability of EGC to make dividends and other distributions to us and our subsidiaries. Under the Amendment, EGC is permitted to make dividends and other distributions in an amount of up to $350 million per calendar year to the extent that, following each distribution, EGC and its subsidiaries have available liquidity, in the form of cash and available borrowing capacity under the First Lien Credit Agreement, of the greater of $150 million or 15% of the borrowing base under the First Lien Credit Agreement. Further, the amendment limits the total aggregate distributions made by EGC to a maximum of $70 million plus 50% of the cumulative consolidated net income of EGC between October 1, 2010 and the most recently ended fiscal quarter, and requires that the making of any such dividend or other distributions must otherwise comply with all contractual restrictions and obligations applicable to EGC.

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

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end of each fiscal quarter. In addition, EGC is subject to various other covenants including, but not limited to, those limiting its ability to declare and pay dividends or other payments, its ability to incur debt, restrictions on change of control, the 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, 2013, EGC was in compliance with all covenants under the 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”). It 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 any equity raised. EGC incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is 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.

EGC believes that the fair value of the $750 million of 9.25% Senior Notes outstanding as of June 30, 2013 was $825 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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

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”). It 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. EGC incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is 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.

EGC believes that the fair value of the $250 million of 7.75% Senior Notes outstanding as of June 30, 2013 was $257.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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

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, 2013, 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.

	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)	$	1,370,045	$	19,554	$	7,604	$	1,092,887	$	250,000
Interest on long-term debt(1)		482,500		101,310		201,536		161,086		18,568
Operating leases(2)		16,040		2,961		6,035		5,684		1,360
Performance bonds(2)		44,452		17,175		27,277
Drilling rig commitments(2)		107,617		98,937		8,680
Letters of credit(2)		225,315		315				225,000
Total contractual obligations		2,245,969		240,252		251,132		1,484,657		269,928
Other Obligations
Asset retirement obligations(3)		287,818		29,500		26,177		27,340		204,801
Total obligations	$	2,533,787	$	269,752	$	277,309	$	1,511,997	$	474,729

(1) See Note 6 — Long-Term Debt of Notes to Consolidated Financial Statements in this Form 10-K for details of our long-term debt.

(2) See Note 15 — Commitments and Contingencies of Notes to Consolidated Financial Statements in this Form 10-K for discussion of these commitments.

(3) See Note 8 — Asset Retirement Obligations of Notes to Consolidated Financial Statements in this Form 10-K 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. GAAP, with no need for management’s judgment in selecting in their application. There are also areas in which management’s judgment in selecting any available alternative would not produce a materially different result. However, certain accounting policies are important to the portrayal of our financial condition and results of operations and require management’s most subjective or complex judgments. In applying those policies, management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. Our critical accounting policies and estimates are set forth below. Certain of these accounting policies and estimates are particularly sensitive because of

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their complexity and the possibility that future events affecting them may differ materially from our management’s current judgment. Our most sensitive accounting estimate affecting our financial statements is our oil and gas reserves, which are highly sensitive to changes in oil and gas prices that have been volatile in recent years. Although decreases in oil and gas prices are partially offset by our hedging program, to the extent reserves are adversely impacted by reductions in oil and gas prices, we could experience increased depreciation, depletion and amortization expense in future periods.

Use of Estimates.  The preparation of 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.

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, 2013, 2012 and 2011, a 10% decrease in oil and gas prices would not impact the results of our full cost ceiling limitation test.

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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.

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.

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. At June 30, 2013

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we maintained a $22.5 million valuation allowance against our net deferred tax assets due to our judgment that our existing State of Louisiana net operating loss (NOL) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly. 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 adopted the provisions of ASC Topic 740-10 (formally known as FIN 48, addressing “Uncertain Tax Positions”) and applied this guidance as of July 1, 2007. As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of ASC Topic 740-10 nor have we recorded any gross unrecognized tax benefit 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.

In February 2013, the FASB issued Accounting Standards Update No. 2013-02: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 updates ASU 2011-12 and requires companies to report information of significant changes in accumulated balances of each component of AOCI included in equity in one place. Total changes in AOCI by component can either be presented on the face of the financial statements or in the notes. ASU 2013-02 is effective for fiscal years and interim periods within those years beginning after December 15, 2012, with early adoption permitted. We do not expect the adoption ASU 2013-02 to have any effect on our consolidated financial position, results of operations or cash flows, other than presentation.

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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, 2013, 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 also use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded 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-WTI and/or BRENT-IPE) plus the difference between the purchased put and the sold put strike price.

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At June 30, 2013, our natural gas contracts outstanding had an asset position of $6.8 million. A 10% increase in natural gas prices would reduce the fair value by approximately $3.7 million, while a 10% decrease in natural gas prices would increase the fair value by approximately $3.1 million. Also, at June 30, 2013, our crude oil contracts outstanding had an asset position of $53.5 million. A 10% increase in crude oil prices would reduce the fair value by approximately $45.8 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $57.2 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2013.

As of June 30, 2013, we had the following net open crude oil derivative positions:

								Weighted Average Contract Price
								Swaps		Collars/Put Spreads
Period	Type of Contract		Index		Volumes (MBbls)			Fixed Price		Sub Floor		Floor		Ceiling
July 2013 – December 2013		Three-Way Collars		Oil-Brent-IPE		2,024	(1)			$	85.91	$	105.91	$	125.88
July 2013 – December 2013		Put Spreads		Oil-Brent-IPE		920					87.00		106.00
July 2013 – December 2013		Three-Way Collars		NYMEX-WTI		920					70.00		90.00		136.32
July 2013 – December 2013		Collars		NYMEX-WTI		644							73.57		105.63
July 2013 – December 2013		Swaps		NYMEX-WTI		92		$	86.60
July 2013 – December 2013		Swaps		NYMEX-WTI		(92	)		88.20
January 2014 – December 2014		Three-Way Collars		Oil-Brent-IPE		2,373					68.08		88.08		130.88
January 2014 – December 2014		Collars		Oil-Brent-IPE		730							90.00		108.38
January 2014 – December 2014		Three-Way Collars		NYMEX-WTI		3,650					70.00		90.00		137.14
January 2015 – December 2015		Three-Way Collars		Oil-Brent-IPE		1,825					72.00		92.00		111.56

(1) The Oil-Brent-IPE three-way collars for the period from July 2013 through December 2013 include the repositioned derivative contracts referred to above. The newly purchased put spreads have been designated as hedges whereas the call option remaining from the collar after the put was sold no longer qualifies for hedge accounting. However, the combination of the put spread and call contracts effectively result into a three-way collar.

As of June 30, 2013, we had the following net open natural gas derivative positions:

							Weighted Average Contract Price
							Collars/Put Spreads
Period	Type of Contract		Index		Volumes (MMBtu)		Sub Floor		Floor		Ceiling
July 2013 – December 2013		Three-Way Collars		NYMEX-HH		8,580	$	3.72	$	4.54	$	5.37
July 2013 – December 2013		Put Spreads		NYMEX-HH		620		4.00		4.90
January 2014 – December 2014		Three-Way Collars		NYMEX-HH		10,950		3.25		4.00		4.74

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 have utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. During the quarter ended September 30, 2011, the Company began utilizing ICE Brent Futures (“Brent”) collars, three-way collars and put spreads in our hedging portfolio as we believe that the Brent prices are more reflective of our realized crude oil production pricing (HLS). Thus by modifying our hedge portfolio to include Brent benchmarks for crude hedging, we aim to more effectively manage our exposure and manage our price risk.

For a complete discussion of our open commodity derivatives as of June 30, 2013, please see Note 9 — Derivative Financial Instruments to our Consolidated Financial Statements in this Form 10-K.

70

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 consider our interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 75% percent of the Company’s debt. As of June 30, 2013, total debt included $339 million of floating-rate debt. As a result, our period-end interest costs will fluctuate based on short-term interest rates on approximately 25 percent of our total debt outstanding as of June 30, 2013. A 10 percent change in floating interest rates on period-end floating debt balances would change annual interest expense by approximately $85,000. 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.

71

Item 8. Financial Statements and Supplementary Data

	Page
Management’s Report on Internal Control over Financial Reporting		73
Reports of Independent Registered Public Accounting Firm		74
Consolidated Financial Statements
Consolidated Balance Sheets		76
Consolidated Statements of Income		77
Consolidated Statements of Comprehensive Income (Loss)		78
Consolidated Statements of Stockholders’ Equity		79
Consolidated Statements of Cash Flows		80
Notes to Consolidated Financial Statements		81

72

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. (“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 U.S. 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, 2013. 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 (1992). Based on this assessment, our management has concluded that, as of June 30, 2013, 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, 2013. This report, dated August 21, 2013, appears on the following page.

73

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, 2013, based on criteria established in Internal Control — Integrated Framework (1992) 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, 2013, based on criteria established in Internal Control — Integrated Framework (1992) 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, 2013 and 2012, 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, 2013, and our report dated August 21, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ UHY LLP

Houston, Texas
August 21, 2013

74

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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three fiscal years in the period ended June 30, 2013, 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, 2013, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated August 21, 2013 expressed an unqualified opinion on the effective operation of internal control over financial reporting.

/s/ UHY LLP

Houston, Texas
August 21, 2013

75

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

	June 30,
	2013			2012
ASSETS
Current Assets
Cash and cash equivalents	$	—		$	117,087
Accounts receivable
Oil and natural gas sales		132,521			126,107
Joint interest billings		9,505			3,840
Insurance and other		6,745			5,420
Prepaid expenses and other current assets		50,738			63,029
Derivative financial instruments		38,389			32,497
Total Current Assets		237,898			347,980
Property and Equipment
Oil and natural gas properties – full cost method of accounting, including $422.6 million and $418.8 million of unevaluated properties not being amortized at June 30, 2013 and 2012, respectively		3,289,505			2,698,213
Other property and equipment		17,003			9,533
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		3,306,508			2,707,746
Other Assets
Derivative financial instruments		21,926			45,496
Equity investments		12,799			2,117
Debt issuance costs, net of accumulated amortization and other assets		32,580			27,608
Total Other Assets		67,305			75,221
Total Assets	$	3,611,711		$	3,130,947
LIABILITIES
Current Liabilities
Accounts payable	$	219,610		$	156,959
Accrued liabilities		105,192			118,818
Notes payable		22,524			22,211
Deferred income taxes		20,517			—
Asset retirement obligations		29,500			34,457
Derivative financial instruments		40			—
Current maturities of long-term debt		19,554			4,284
Total Current Liabilities		416,937			336,729
Long-term debt, less current maturities		1,350,491			1,014,060
Deferred income taxes		140,804			104,280
Asset retirement obligations		258,318			266,958
Other liabilities		7,915			3,080
Total Liabilities		2,174,465			1,725,107
Commitments and Contingencies (Note 15)
Stockholders’ Equity
Preferred stock, $0.001 par value, 7,500,000 shares authorized at June 30, 2013 and 2012, respectively
7.25% Convertible perpetual preferred stock, 8,000 shares issued and outstanding at June 30, 2013 and 2012, respectively		—			—
5.625% Convertible perpetual preferred stock, 813,188 and 814,117 shares issued and outstanding at June 30, 2013 and 2012, respectively		1			1
Common stock, $0.005 par value, 200,000,000 shares authorized and 79,425,473 and 79,147,340 shares issued and 76,485,910 and 78,837,697 shares outstanding at June 30, 2013 and 2012, respectively		397			396
Additional paid-in capital		1,512,311			1,501,785
Accumulated deficit		(29,352	)		(153,945	)
Accumulated other comprehensive income, net of income taxes		26,552			57,603
Treasury stock, at cost, 2,938,900 shares at June 30, 2013		(72,663	)		—
Total Stockholders’ Equity		1,437,246			1,405,840
Total Liabilities and Stockholders’ Equity	$	3,611,711		$	3,130,947

 
 
See accompanying Notes to Consolidated Financial Statements

76

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

	Year Ended June 30,
	2013			2012			2011
Revenues
Crude oil sales	$	1,080,982		$	1,186,631		$	719,683
Natural gas sales		127,863			116,772			139,687
Total Revenues		1,208,845			1,303,403			859,370
Costs and Expenses
Lease operating		337,163			310,815			239,478
Production taxes		5,246			7,261			3,336
Gathering and transportation		24,168			16,371			12,499
Depreciation, depletion and amortization		376,224			367,463			293,479
Accretion of asset retirement obligations		30,885			39,161			32,127
General and administrative expense		71,598			86,276			75,091
Loss (gain) on derivative financial instruments		1,756			(7,228	)		(5,563	)
Total Costs and Expenses		847,040			820,119			650,447
Operating Income		361,805			483,284			208,923
Other Income (Expense)
Bridge loan commitment fees		—			—			(4,500	)
Loss on retirement of debt		—			—			(21,855	)
Loss from equity method investees		(6,397	)		—			—
Other income – net		1,965			71			198
Interest expense		(108,659	)		(108,882	)		(105,849	)
Total Other Expense		(113,091	)		(108,811	)		(132,006	)
Income Before Income Taxes		248,714			374,473			76,917
Income Tax Expense		86,633			38,646			12,262
Net Income		162,081			335,827			64,655
Induced Conversion of Preferred Stock		—			6,068			24,348
Preferred Stock Dividends		11,496			13,028			12,600
Net Income Available for Common Stockholders	$	150,585		$	316,731		$	27,707
Earnings per Share
Basic	$	1.90		$	4.10		$	0.42
Diluted	$	1.86		$	3.85		$	0.42
Weighted Average Number of Common Shares Outstanding
Basic		79,063			77,310			66,356
Diluted		87,263			87,208			66,459

 
 
See accompanying Notes to Consolidated Financial Statements

77

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

	Year Ended June 30,
	2013			2012			2011
Net Income	$	162,081		$	335,827		$	64,655
Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		(7,961	)		228,398			(136,566	)
Effective portion reclassified to earnings during the period		(39,810	)		(34,418	)		(11,418	)
Total Other Comprehensive Income (Loss)		(47,771	)		193,980			(147,984	)
Income Tax Expense (Benefit)		(16,720	)		67,893			(51,794	)
Net Other Comprehensive Income (Loss)		(31,051	)		126,087			(96,190	)
Comprehensive Income (Loss)	$	131,030		$	461,914		$	(31,535	)

 
 
See accompanying Notes to Consolidated Financial Statements

78

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

	Preferred Stock					Common Stock		Treasury Stock			Paid-in Capital			Accumulated Deficit			Other Comprehensive Income (Loss)			Total Stockholders’ Equity
	5.625%		7.25%
Balance, June 30, 2010			$	11		$	254				$	901,457		$	(492,867	)	$	27,706		$	436,561
Common stock issued, net of direct costs							71					283,322									283,393
Common stock based compensation							1					4,442									4,443
Preferred stock issued, net of direct costs	$	1										278,391									278,392
Preferred stock converted to common				(11	)		53					(42	)
Preferred stock dividends															(12,600	)					(12,600	)
Preferred stock inducement							2					12,389			(24,348	)					(11,957	)
Comprehensive income (loss)															64,655			(96,190	)		(31,535	)
Balance, June 30, 2011		1		—			381					1,479,959			(465,160	)		(68,484	)		946,697
Common stock issued, net of direct costs							1					10,051									10,052
Common stock based compensation							2					11,758									11,760
Preferred stock converted to common							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		1		—			396					1,501,785			(153,945	)		57,603			1,405,840
Common stock issued, net of direct costs							1					7,021									7,022
Common stock based compensation												3,505									3,505
Repurchase of company common stock								$	(72,663	)											(72,663	)
Common stock dividends															(25,992	)					(25,992	)
Preferred stock dividends															(11,496	)					(11,496	)
Comprehensive income															162,081			(31,051	)		131,030
Balance, June 30, 2013	$	1	$	—		$	397	$	(72,663	)	$	1,512,311		$	(29,352	)	$	26,552		$	1,437,246

 
 
See accompanying Notes to Consolidated Financial Statements

79

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

	Year Ended June 30,
	2013			2012			2011
Cash Flows From Operating Activities
Net income	$	162,081		$	335,827		$	64,655
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		376,224			367,463			293,479
Deferred income tax expense		73,761			38,796			12,169
Change in derivative financial instruments
Proceeds from sale of derivative instruments		760			66,522			42,577
Other – net		(27,516	)		(52,155	)		(37,047	)
Accretion of asset retirement obligations		30,885			39,161			32,127
Loss from equity method investees		6,397			—			—
Amortization of debt discount and premium		—			—			(43,521	)
Amortization and write-off of debt issuance costs and other		6,898			7,559			15,772
Stock-based compensation		3,505			11,760			4,443
Payment of interest in-kind		—			—			2,225
Changes in operating assets and liabilities
Accounts receivable		1,690			(4,995	)		(49,745	)
Prepaid expenses and other current assets		12,499			(15,890	)		(13,272	)
Settlement of asset retirement obligations		(41,939	)		(14,990	)		(73,974	)
Accounts payable and accrued liabilities		32,903			6,456			137,837
Net Cash Provided by Operating Activities		638,148			785,514			387,725
Cash Flows from Investing Activities
Acquisitions		(161,164	)		(6,401	)		(1,012,262	)
Capital expenditures		(816,105	)		(570,670	)		(281,233	)
Insurance payments received		—			6,472			—
Change in equity method investments		(16,693	)		(2,201	)		—
Proceeds from the sale of properties		—			2,750			38,431
Other		(41	)		457			(8	)
Net Cash Used in Investing Activities		(994,003	)		(569,593	)		(1,255,072	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		7,021			9,839			562,112
Conversion of preferred stock to common stock		—			(6,040	)		(11,957	)
Repurchase of company common stock		(58,666	)		—			—
Dividends to shareholders – common		(25,992	)		—			—
Dividends to shareholders – preferred		(11,496	)		(18,682	)		(12,313	)
Proceeds from long-term debt		1,576,551			896,717			1,829,828
Payments on long-term debt		(1,243,848	)		(1,008,300	)		(1,456,190	)
Debt issuance costs		(4,805	)		—			(29,614	)
Other		3			(775	)		(336	)
Net Cash Provided by (Used in) Financing Activities		238,768			(127,241	)		881,530
Net Increase (Decrease) in Cash and Cash Equivalents		(117,087	)		88,680			14,183
Cash and Cash Equivalents, beginning of year		117,087			28,407			14,224
Cash and Cash Equivalents, end of year	$	—		$	117,087		$	28,407

 
 
See accompanying Notes to Consolidated Financial Statements

80

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, 2013 and 2012, 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.

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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.

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 of the future costs are added to the capitalized cost of our oil and gas properties and recorded as a long-term

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

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.

Common Stock.  Refers to the $0.005 par value per share capital stock as designated in the Company’s Certificate of Incorporation. Treasury Stock is accounted for using the cost method.

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, 2013, 2012 and 2011 was $37.6 million, $38.3 million and $37.8 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. At June 30, 2013 we maintained a $22.5 million valuation allowance against our net deferred tax assets due to our judgment that our existing State of Louisiana net operating loss (NOL) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly. 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 adopted the provisions of ASC Topic 740-10 (formally known as FIN 48, addressing “Uncertain Tax Positions”) and applied this guidance as of July 1, 2007. As of the adoption date, we did not record a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

cumulative effect adjustment related to the adoption of ASC Topic 740-10 nor have we recorded any gross unrecognized tax benefit related to Uncertain Tax Positions.

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.

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.

In February 2013, the FASB issued Accounting Standards Update No. 2013-02: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 updates ASU 2011-12 and requires companies to report information of significant changes in accumulated balances of each component of other comprehensive income included in equity in one place. Total changes in AOCI by component can either be presented on the face of the financial statements or in the notes. ASU 2013-02 is effective for fiscal years and interim periods within those years beginning after December 15, 2012, with early adoption permitted. We do not expect the adoption ASU 2013-02 to have any effect on our consolidated financial position, results of operations or cash flows, other than presentation.

Note 3 — Acquisitions and Dispositions

ExxonMobil oil and gas properties interests acquisition

On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“Exxon”) for a total cash consideration of approximately $32.8 million. The GOM Interests cover 5,000 gross acres on Vermilion Block 164 (“VR 164”). We are the operator of these properties. In addition to acquiring the GOM Interests, we entered into a joint venture

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

agreement with Exxon to explore for oil and gas on nine contiguous blocks adjacent to VR 164 in shallow waters on the GOM shelf. We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012.

Revenues and expenses related to the GOM Interests from the closing date of October 17, 2012 are included in our consolidated statements of income. The acquisition of the GOM Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on October 17, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	10,447
Oil and natural gas properties – unevaluated		27,721
Asset retirement obligations		(5,351	)
Cash paid	$	32,817

Dynamic Offshore oil and gas properties interests acquisition

On November 7, 2012, we acquired 100% of the interests (“Dynamic Interests”) held by Dynamic Offshore Resources, LLC (“Dynamic”) on VR 164 for approximately $7.2 million.

Revenues and expenses related to the Dynamic Interests from the closing date of November 7, 2012 are included in our consolidated statements of income. The acquisition of the Dynamic Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	1,753
Oil and natural gas properties – unevaluated		6,571
Asset retirement obligations		(1,091	)
Cash paid	$	7,233

McMoRan oil and gas properties interests acquisition

On January 17, 2013, we closed on the acquisition of certain onshore Louisiana interests in the Bayou Carlin field (“Bayou Carlin Interests”) from McMoRan Oil and Gas, LLC (“McMoRan”) for a total cash consideration of $79.3 million. This acquisition is effective January 1, 2013. We are the operator of these properties.

Revenues and expenses related to the Bayou Carlin Interests from the closing date of January 17, 2013 are included in our consolidated statements of income. The acquisition of the Bayou Carlin Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	62,499
Oil and natural gas properties – unevaluated		17,184
Asset retirement obligations		(382	)
Cash paid	$	79,301

RoDa oil and gas properties interests acquisition

On March 14, 2013, we acquired 100% of the interests (“RoDa Interests”) held by RoDa Drilling LP (“RoDa”) in the Bayou Carlin field for $32.7 million. This acquisition is effective January 1, 2013.

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Note 3 — Acquisitions and Dispositions  – (continued)

Revenues and expenses related to the RoDa Interests from the closing date of March 14, 2013 are included in our consolidated statements of income. The acquisition of the RoDa Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 14, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	32,777
Asset retirement obligations		(115	)
Cash paid	$	32,662

Tammany oil and gas properties interests acquisition

On June 28, 2013, we closed on the acquisition of certain offshore Louisiana interests in the West Delta field (“West Delta Interests”) from Tammany Energy Ventures, LLC (“Tammany”) for a total cash consideration of $8.3 million. This acquisition is effective June 1, 2013. We will be the operator of these properties.

Revenues and expenses related to the West Delta Interests will be included in our consolidated statements of income from July 1, 2013. The acquisition of West Delta Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on June 28, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	8,626
Asset retirement obligations		(338	)
Cash paid	$	8,288

The fair values of evaluated and unevaluated oil and gas properties and asset retirement obligations for the above acquisitions 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) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

Apache Joint Venture

On February 1, 2013, we entered into an Exploration Agreement (“Agreement”) with Apache Corporation (“Apache”) to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central Gulf of Mexico Shelf. We have a 25% participation interest in the Agreement, which expires on February 1, 2018.

The area of mutual interest under this agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million of which approximately $17.9 million was incurred through June 30, 2013. We have presently consented to participate in drilling one well and have an option to participate in two other wells under the current drilling program. Drilling on the first well commenced in May 2013 and our share of the costs related to this well at June 30, 2013 were approximately $8.1 million.

As of June 30, 2013, we paid consideration of approximately $3 million, being our participation interest, to Apache for 21 non-producing primary-term leases.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Property and Equipment

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

	June 30,
	2013		2012
Oil and gas properties
Proved properties	$	5,335,737	$	4,375,984
Less: accumulated depreciation, depletion, amortization and impairment		2,468,783		2,096,531
Proved properties		2,866,954		2,279,453
Unevaluated properties		422,551		418,760
Oil and gas properties		3,289,505		2,698,213
Other property and equipment		32,786		22,132
Less: accumulated depreciation		15,783		12,599
Other property and equipment		17,003		9,533
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	3,306,508	$	2,707,746

Note 5 — Equity Method Investments

20% interest in Energy XXI M21K, LLC (“EXXI M21K”)

We own a 20% interest in EXXI M21K. EXXI M21K engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K, LLC (“M21K”).

On June 4, 2012, M21K 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. The effective date of the acquisition is January 1, 2012.

On July 19, 2012, M21K 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 M21K is a guarantor of a $100 million first lien credit facility agreement entered into by M21K (“M21K First Lien Credit Agreement”). Simultaneous with the closing of the acquisition of assets from EP Energy, M21K entered into the First Amendment to the M21K First Lien Credit Agreement, which made technical changes to defined terms and hedging requirements, as well as establishing the borrowing base under the facility at $25 million.

On December 12, 2012, in conjunction with the name change from Natural Gas Partners Assets, LLC to M21K, LLC, M21K entered into the Second Amendment to the M21K First Lien Credit Agreement to reflect the name change and make technical changes to borrowing procedures.

On April 9, 2013, M21K entered into the Third Amendment to the M21K First Lien Credit Agreement that made technical modification of a defined term and reduced the borrowing base to $24 million with further reduction to $20 million within ninety days from the amendment date.

On July 25, 2013 M21K entered into a PSA Agreement with LLOG Exploration Offshore, L.L.C. (“LLOG Exploration”) to acquire interests in certain oil and gas fields owned by LLOG Exploration. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was $103 million. The effective date of the acquisition is April 1, 2013. In connection with this acquisition, M21K paid LLOG Exploration a performance deposit of $10.3 million. The closing of this acquisition is scheduled to occur on or before August 30, 2013.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Equity Method Investments  – (continued)

We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K for the EP Energy property acquisition. See Note 13 — Related Party Transactions of Notes to Consolidated Financial Statements in this Form 10-K.

As of June 30, 2013, our investment in EXXI M21K was approximately $12.4 million and we had incurred $2.9 million in equity losses for the year ended June 30, 2013.

49% interest in Ping Energy XXI Limited (“Ping Energy”)

Our wholly-owned subsidiary Energy XXI International Limited (“EXXI International”) owns a 49% interest in Ping Energy, which is active in the pursuit to identify and acquire exploratory, developmental and producing oil and gas properties in South East Asia.

As of June 30, 2013, our investment in Ping Energy was approximately $0.4 million and we had incurred $3.5 million in equity losses for the year ended June 30, 2013.

Note 6 — Long-Term Debt

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

	June 30,
	2013		2012
Revolving credit facility	$	339,000	$	—
9.25% Senior Notes due 2017		750,000		750,000
7.75% Senior Notes due 2019		250,000		250,000
4.14% Promissory Note due 2017		5,187		—
Derivative instruments premium financing		24,681		17,387
Capital lease obligations		1,177		957
Total debt		1,370,045		1,018,344
Less current maturities		19,554		4,284
Total long-term debt	$	1,350,491	$	1,014,060

Maturities of long-term debt as of June 30, 2013 are as follows (in thousands):

Year Ending June 30,
2014	$	19,554
2015		6,712
2016		892
2017		471
2018		1,092,416
Thereafter		250,000
Total	$	1,370,045

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, Energy XXI Gulf Coast, Inc. (“EGC”), in May 2011. This facility, as amended, has lender commitments of $1,700 million and matures on April 9, 2018. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving

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ENERGY XXI (BERMUDA) LIMITED
  
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Note 6 — Long-Term Debt  – (continued)

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 allowed to pay us a limited amount of distributions, subject to certain terms and conditions.

On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement, which provided EGC the ability to make distributions to us for various purposes, subject to varying limitations depending on the purpose of the distribution. The ability of EGC to make dividends was subject to EGC meeting minimum liquidity and maximum revolver utilization thresholds, and were further limited to an aggregate cumulative amount equal to $70 million plus 50% of our cumulative Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter. The ability of EGC to make dividend payments to us was modified in subsequent amendments.

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; (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.

On October 19, 2012, EGC entered into the Third Amendment (the “Third Amendment”) to the First Lien Credit Agreement. The Third Amendment provides changes, supplements, and other modifications for information specific to the lenders under the First Lien Credit Agreement and increased the borrowing base to $825 million.

On April 9, 2013, EGC entered into the Fourth Amendment (the “Fourth Amendment”) to the First Lien Credit Agreement. The Fourth Amendment included the following revisions: (a) extension of the maturity date to April 9, 2018, (b) increase of commitments under the First Lien Credit Agreement from $925 million to $1,700 million, (c) increase in the borrowing base to $850 million, (d) reduction of the ranges of applicable margins on all borrowing by 0.25% to 0.50%, (e) approval of an increase in the cash distribution basket under which EGC can make dividend payments on its preferred and common stock, from $17 million to $50 million per calendar year, (f) increase in the general basket of permitted unsecured indebtedness from $250 million to $750 million, subject to a reduction in the borrowing base of 25 percent of any unsecured indebtedness issued in excess of $250 million, and (g) approval of additional ability of an affiliated entity to reinsure the assets and operations of EGC and its subsidiaries.

On May 1, 2013, EGC entered into the Fifth Amendment (the “Fifth Amendment”) to the First Lien Credit Agreement. The Fifth Amendment provides changes and other modifications to the First Lien Credit Agreement to increase the ability of EGC to make dividends and other distributions to us. Under the Amendment, EGC is permitted to make dividends and other distributions in an amount of up to $350 million per calendar year to the extent that, following each distribution, EGC and its subsidiaries have liquidity, in the form of cash and available borrowing capacity under the First Lien Credit Agreement, of the greater of $150 million or 15% of the borrowing base under the First Lien Credit Agreement. Further, the amendment limits the total aggregate distributions made by EGC to a maximum of $70 million plus 50% of the cumulative consolidated net income of EGC between October 1, 2010 and the most recently ended fiscal quarter, and requires that the making of any such dividend or other distributions must otherwise comply with all contractual restrictions and obligations applicable to EGC.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

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, it is subject to various other covenants including, but not limited to, those limiting its ability to declare and pay dividends or other payments, its ability to incur debt, restrictions on change of control, the 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, 2013, EGC was in compliance with all covenants under the 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”). It 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 any equity raised. EGC incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is 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.

EGC believes that the fair value of the $750 million of 9.25% Senior Notes outstanding as of June 30, 2013 was $825 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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

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”). It 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. EGC incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is 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.

EGC believes that the fair value of the $250 million of 7.75% Senior Notes outstanding as of June 30, 2013 was $257.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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

Promissory Note

In September 2012, we entered into a promissory note of $5.5 million to acquire other property and equipment. Under this note we are required to make a monthly payment of approximately $52,000 and one lump-sum payment of $3.3 million at maturity, in October 2017. This note carries an interest of 4.14% per annum.

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, 2013 and June 30, 2012, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $24.7 million and $17.4 million, respectively.

Interest Expense

For the years ended June 30, 2013, 2012 and 2011, interest expense consisted of the following (in thousands):

	Year Ended June 30,
	2013		2012		2011
Revolving credit facility	$	11,816	$	9,420	$	10,080
9.25% Senior Notes due 2017		69,375		69,375		37,193
7.75% Senior Notes due 2019		19,375		19,375		6,727
10% Senior Notes due 2013		—		—		20,811
16% Second Lien Notes due 2014		—		—		24,967
Amortization of debt issue cost – Revolving credit facility		4,303		4,881		6,999
Amortization of debt issue cost – 10% Senior Notes due 2013		—		—		1,681
Amortization of debt issue cost – 16% Second Lien Notes due 2014		—		—		54
Amortization of debt issue cost – 9.25% Senior Notes due 2017		2,206		2,206		1,196
Amortization of debt issue cost – 7.75% Senior Notes due 2019		388		388		141
Discount amortization – 16% Second Lien Notes due 2014 (Private Placement)		—		—		1,894
Premium amortization – 16% Second Lien Notes due 2014 (Exchange Offer)		—		—		(6,889	)
Derivative instruments premium financing and other		1,196		1,347		995
Settlement of Lehman Brothers liability		—		1,890		—
	$	108,659	$	108,882	$	105,849

91

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7 — Notes Payable

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 matured and was repaid on December 26, 2012.

In July 2012, we entered into a note to finance a portion of our insurance premiums. The note was for a total face amount of $3.6 million and bore interest at an annual rate of 1.667%. The note matured and was repaid on May 1, 2013.

In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums. The note was for a total face amount of $0.6 million and bears interest at an annual rate of 1.774%. The note amortizes over the remaining term of the insurance, which matures October 23, 2013. The balance outstanding as of June 30, 2013 was $0.2 million.

In May 2013, 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 $24.8 million and bears interest at an annual rate of 1.623%. The note amortizes over the remaining term of the insurance, which matures April 26, 2014. The balance outstanding as of June 30, 2013 was $22.3 million.

Note 8 — Asset Retirement Obligations

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

	Year Ended June 30,
	2013			2012
Balance at beginning of year	$	301,415		$	323,242
Liabilities acquired		7,277			125
Liabilities incurred		18,486			2,268
Liabilities settled		(41,939	)		(14,990	)
Revisions in estimated cash flows		(28,306	)		(48,391	)
Accretion expense		30,885			39,161
Total balance at end of year		287,818			301,415
Less current portion		29,500			34,457
Long-term balance at end of year	$	258,318		$	266,958

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

92

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options 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-WTI and/or BRENT-IPE) 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. During the 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 at various times since the quarter ended March 31, 2009 through the quarter ended June 30, 2013, and received $181.3 million. These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts. As of June 30, 2013, we had $9 million of monetized amounts remaining in OCI of which $4.5 million will be recognized during each of the quarters ending September 30, 2013 and December 31, 2013, respectively.

During the year ended June 30, 2013, we repositioned certain hedge positions by selling puts on certain existing calendar year 2013 hedge collar contracts and purchasing new put spread contracts. The $2.2 million received from the sale of puts were recorded as deferred hedge revenue and will be recognized in income over the life of the underlying hedge contracts through December 31, 2013. As of June 30, 2013, we had $1.3 million in deferred hedge revenue of which $0.7 million and $0.6 million will be recognized during the quarters ending September 30, 2013 and December 31, 2013, respectively.

As of June 30, 2013, we had the following net open crude oil derivative positions:

								Weighted Average Contract Price
								Swaps		Collars/Put Spreads
Period	Type of Contract		Index		Volumes (MBbls)			Fixed Price		Sub Floor		Floor		Ceiling
July 2013 – December 2013		Three-Way Collars		Oil-Brent-IPE		2,024	(1)			$	85.91	$	105.91	$	125.88
July 2013 – December 2013		Put Spreads		Oil-Brent-IPE		920					87.00		106.00
July 2013 – December 2013		Three-Way Collars		NYMEX-WTI		920					70.00		90.00		136.32
July 2013 – December 2013		Collars		NYMEX-WTI		644							73.57		105.63
July 2013 – December 2013		Swaps		NYMEX-WTI		92		$	86.60
July 2013 – December 2013		Swaps		NYMEX-WTI		(92	)		88.20
January 2014 – December 2014		Three-Way Collars		Oil-Brent-IPE		2,373					68.08		88.08		130.88
January 2014 – December 2014		Collars		Oil-Brent-IPE		730							90.00		108.38
January 2014 – December 2014		Three-Way Collars		NYMEX-WTI		3,650					70.00		90.00		137.14
January 2015 – December 2015		Three-Way Collars		Oil-Brent-IPE		1,825					72.00		92.00		111.56

93

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

(1) The Oil-Brent-IPE three-way collars for the period from July 2013 through December 2013 include the repositioned derivative contracts referred to above. The newly purchased put spreads have been designated as hedges whereas the call option remaining from the collar after the put was sold no longer qualifies for hedge accounting. However, the combination of the put spread and call contracts effectively result into a three-way collar.

As of June 30, 2013, we had the following net open natural gas derivative positions:

							Weighted Average Contract Price
							Collars/Put Spreads
Period	Type of Contract		Index		Volumes (MMBtu)		Sub Floor		Floor		Ceiling
July 2013 – December 2013		Three-Way Collars		NYMEX-HH		8,580	$	3.72	$	4.54	$	5.37
July 2013 – December 2013		Put Spreads		NYMEX-HH		620		4.00		4.90
January 2014 – December 2014		Three-Way Collars		NYMEX-HH		10,950		3.25		4.00		4.74

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

	Asset Derivative Instruments								Liability Derivative Instruments
	June 30, 2013				June 30, 2012				June 30, 2013				June 30, 2012
	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	$	52,216		Current	$	66,716		Current	$	14,609		Current	$	34,462
		Non-Current		42,263		Non-Current		103,462		Non-Current		20,337		Non-Current		58,229
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments		Current		1,976		Current		326		Current		1,234		Current		83
		Non-Current		—		Non-Current		451		Non-Current		—		Non-Current		188
Total			$	96,455			$	170,955			$	36,180			$	92,962

94

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

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

	Year Ended June 30,
	2013			2012			2011
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(13,296	)	$	(438	)	$	58,186
Natural gas sales		(15,110	)		(28,164	)		(37,872	)
Total cash settlements		(28,406	)		(28,602	)		20,314
Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments
Ineffective portion of commodity derivative instruments		881			(3,479	)		(21	)
Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market (gain) loss		1,686			(4,542	)		(3,686	)
Unrealized mark to market (gain) loss		(811	)		793			(1,856	)
Total (gain) loss on derivative financial instruments		1,756			(7,228	)		(5,563	)
Total (gain) loss	$	(26,650	)	$	(35,830	)	$	14,751

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, 2013
Commodity Derivative Instruments	$	31,051
Revenues				$	(25,876	)
Loss (gain) on derivative financial instruments							$	881
Total	$	31,051		$	(25,876	)	$	881
Year Ended June 30, 2012
Commodity Derivative Instruments	$	(126,087	)
Revenues				$	(22,372	)
Loss (gain) 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	)
Loss (gain) on derivative financial instruments							$	(21	)
Total	$	96,190		$	(7,422	)	$	(21	)

95

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $27.8 million ($18.1 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 to another 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, 2013, we had no deposits for collateral with our counterparties.

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 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.

We paid quarterly cash dividends of $0.07 per share to holders of our common stock on September 14, 2012, December 14, 2012 and March 15, 2013 to shareholders of record on August 31, 2012, November 30, 2012 and March 1, 2013, respectively.

We paid quarterly cash dividends of $0.12 per share to holders of our common stock on June 14, 2013, to shareholders of record on May 31, 2013. On July 17, 2013, our Board of Directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of our common stock. The quarterly dividend will be paid on September 13, 2013 to shareholders of record on August 30, 2013.

In May 2013, our Board of Directors approved a stock repurchase program authorizing us to repurchase up to $250 million in value of our common stock for an extended period of time, in one or more open market transactions. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity and other appropriate factors. The repurchase program does not obligate us to acquire any particular amount of common stock and may be modified or suspended at any time and could be terminated prior to completion. The repurchase program will be funded with cash on hand or borrowings revolving credit facility. Any repurchased shares of common stock will be retained at our subsidiary level, subject to transfer to the parent company where they may be retired.

During the year ended June 30, 2013, we incurred $72.7 million to repurchase 2,938,900 shares of our common stock at a weighted average price per share, excluding fees, of $24.70. In July 2013, we utilized a total of $21.2 million to repurchase 914,000 shares of our common stock at a weighted average price per share, excluding fees, of $23.19 after which, $156.1 million remains available for repurchase under the share repurchase program.

Preferred Stock

Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. Our board of directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Shares of previously issued preferred stock that have been cancelled are available for future issuance.

96

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 the year ended June 30, 2013, we canceled and converted a total of 929 shares of our 5.625% Preferred Stock into a total of 9,183 shares of common stock using a conversion rate ranging from 9.8578 to 9.899 common shares per preferred share.

Note 11 — Supplemental Cash Flow Information

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

	Year Ended June 30,
	2013		2012		2011
Cash paid for interest	$	99,377	$	103,346	$	96,624
Cash paid for income taxes		12,873		—		—

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

	Year Ended June 30,
	2013			2012			2011
Financing of insurance premiums	$	22,524		$	22,211		$	19,853
Preferred stock dividends		—			(138	)		286
Derivative instruments premium financing		18,231			16,259			4,267
Additions to property and equipment by recognizing asset retirement obligations		(9,820	)		(45,998	)		222,438
Repurchase of company common stock		13,997			—			—

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 2011, 2012 and 2013, 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 2011 grant, the initial stock price used in determining the

97

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans  – (continued)

change in stock price is $15.62 per share, for the fiscal year 2012 grant the initial stock price is $34.40 and for the fiscal year 2013 grant the initial stock price is $33.20.

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, 2013 vesting of the July 21, 2012, 2011 and 2010 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.

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

	Year Ended June 30,
	2013		2012		2011
Restricted Stock Units	$	10,707	$	19,315	$	20,314
Performance Units		10,569		31,148		28,480
Total compensation expense recognized	$	21,276	$	50,463	$	48,794

As of June 30, 2013, we have 865,158 unvested Restricted Stock Units and 5,170,042 unvested Performance Based Units.

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, 2013, 2012 and 2011, we issued 213,763 shares, 305,401 shares and 282,047 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, 2013 to December 31, 2013. 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, 2013 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,
	2013		2012		2011
Compensation expense	$	813	$	729	$	567
Shares issued		74,806		46,985		115,323

98

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, 2013, 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,
	2013			2012					2011
	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
Granted		—			—			—		—			—
Vested		—			(100,000	)		17.50		(140,000	)		17.50
Ending balance		—			—		$	17.50		100,000		$	17.50

Our net income for the years ended June 30, 2012 and 2011 includes approximately $0.1 million and $0.2million, 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,
	2013		2012		2011
Profit Sharing Plan	$	2,738	$	3,014	$	2,980
401(k) Plan		3,381		3,195		1,788
Total contributions	$	6,119	$	6,209	$	4,768

Note 13 — Related Party Transactions

We have a 20% interest in EXXI M21K and a 49% interest in Ping Energy. We account for these investments using the equity method. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Form 10-K.

EXXI M21K is the guarantor of a $100 million line of credit entered into by M21K. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Form 10-K.

We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K for EP Energy Property acquisition estimated at $65 million and $1.8 million, respectively. For this guarantee, M21K has agreed to pay us $6.3 million over a period of three years. As of June 30, 2013, we have received $1.9 million related to such guarantee.

99

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,
	2013		2012		2011
Net income	$	162,081	$	335,827	$	64,655
Preferred stock dividends		11,496		13,028		12,600
Induced conversion of preferred stock		—		6,068		24,348
Net income available for common stockholders	$	150,585	$	316,731	$	27,707
Weighted average shares outstanding for basic EPS		79,063		77,310		66,356
Add dilutive securities		8,200		9,898		103
Weighted average shares outstanding for diluted EPS		87,263		87,208		66,459
Earnings per share
Basic	$	1.90	$	4.10	$	0.42
Diluted	$	1.86	$	3.85	$	0.42

For the years ended June 30, 2013, 2012 and 2011, we had 5,474, 4,821 and 11,219,687, respectively, of common stock equivalents that 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, 2013 under the operating lease are as follows (in thousands):

Year Ending June 30,
2014	$	2,962
2015		3,108
2016		2,927
2017		2,981
2018		2,702
Thereafter		1,360
Total	$	16,040

Rent expense, including rent incurred on short-term leases, for the years ended June 30, 2013, 2012 and 2011 was approximately $2,777,000, $2,493,000 and $1,933,000, respectively.

Letters of Credit and Performance Bonds.  We had $225.3 million in letters of credit and $44.5 million of performance bonds outstanding as of June 30, 2013.

Guarantee.  EXXI M21K is the guarantor of a $100 million line of credit entered into by M21K. See Note 5 – Equity Method Investments of Notes to Consolidated Financial Statements in this Form 10-K. We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 — Commitments and Contingencies  – (continued)

estimated at $65 million and $1.8 million, respectively. For this guarantee, M21K has agreed to pay us $6.3 million over a period of three years. See Note 13 — Related Party Transactions of Notes to Consolidated Financial Statements in this Form 10-K.

Drilling Rig Commitments.  The drilling rig commitments represent minimum future expenditures for drilling rig services. The expenditures for drilling rig services will exceed such minimum amounts to the extent we utilize the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract. As of June 30, 2013, we have entered into seven drilling rig commitments:

1)  June 30, 2013 to August 15, 2013 at $49,000 per day

2)  January 1, 2013 to September 30, 2013 at $110,000 per day

3)  October 1, 2013 to June 30, 2014 at $125,000 per day

4)  March 5, 2013 to August 31, 2013 at $135,000 per day

5)  September 1, 2013 to August 31, 2014 at $140,000 per day

6)  February 15, 2013 to July 3, 2013 at $36,000 per day

7)  April 11, 2013 to September 15, 2013 at $20,000 per day

At June 30, 2013, future minimum commitments under these contracts totaled $107.6 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, we have reported cumulative losses and remain marginally in an overall loss position. Due to this previous loss position, coupled with volatility in energy prices (at the time) causing uncertainty as to operating results, we established a valuation allowance of $175.0 million during the year ended June 30, 2009. We have subsequently reduced this allowance by $152.5 million due principally to the reported pre-tax income in the subsequent years. This results in an ending valuation allowance of $22.5 million at June 30, 2013, which relates to certain State of Louisiana net operating loss carryovers that we do not currently believe, on a more-likely-than-not basis, are realizable due to our current focus on offshore operations. 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,
	2013		2012		2011
	(In Thousands)
U.S. income	$	223,337	$	346,887	$	47,751
Non-U.S. income		25,377		27,586		29,166
Income before income taxes	$	248,714	$	374,473	$	76,917

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Income Taxes  – (continued)

The components of our income tax provision are as follows:

	Year Ended June 30,
	2013			2012			2011
	(In Thousands)
Current
United States	$	12,872		$	—		$	—
Non U.S.		—			—			—
State		—			(53	)		93
Total current		12,872			(53	)		93
Deferred
United States		76,222			38,699			12,169
State		(2,461	)		—			—
Total deferred		73,761			38,699			12,169
Total income tax provision	$	86,633		$	38,646		$	12,262

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

	Year Ended June 30,
	2013			2012			2011
	(In Thousands)
Income before income taxes	$	248,714		$	374,473		$	76,917
Statutory rate		35	%		35	%		35	%
Income tax expense computed at statutory rate		87,050			131,066			26,921
Reconciling items
Federal withholding obligation		10,343			10,371			10,343
Nontaxable foreign income		(8,214	)		(9,655	)		(10,208	)
Change in valuation allowance		(59,853	)		(57,031	)		(25,290	)
Revaluation of tax attributes		52,072			7,630			7,186
Debt cancelation – bond repurchase		—			(52,583	)		—
State income taxes, net of federal tax benefit		(2,461	)		(53	)		60
Non-deductible executive compensation and other – net		7,696			8,901			3,250
Tax provision	$	86,633		$	38,646		$	12,262

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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,
	2013			2012
	(In Thousands)
Deferred tax liabilities – current
Federal withholding obligation	$	(20,517	)	$	—
Deferred tax assets – non current
Asset retirement obligation		100,697			105,495
Tax loss carryforwards on U.S. operations		386,899			226,927
Accrued interest expense		65,418			67,701
Deferred interest expense under IRC Sec. 162(j)		28,721			60,403
Employee benefit plans		6,213			14,845
Deferred state taxes		22,494			20,034
Other		6,860			7,311
Total deferred tax assets – non current		617,302			502,716
Deferred tax liabilities
Derivative instruments and other		(10,193	)		(19,404	)
Oil, natural gas properties and other property and equipment		(628,554	)		(406,376	)
Federal withholding obligation		(34,983	)		(58,029	)
Cancellation of debt		(9,680	)		(9,680	)
Tax partnership activity		(52,202	)		(31,159	)
Total deferred tax liabilities – non current		(735,612	)		(524,648	)
Valuation allowance		(22,494	)		(82,348	)
Net deferred tax asset (liability)	$	(161,321	)	$	(104,280	)
Reflected in the accompanying balance sheet as Current deferred tax asset (liability)	$	(20,517	)		—
Non-current deferred tax asset (liability)	$	(140,804	)	$	(104,280	)

The total change in deferred tax assets and liabilities in the year ended June 30, 2013 reflects a $16.7 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, 2013 of $14.3 million related to other comprehensive income which is included in the derivative instruments line.

At June 30, 2013, we have a U.S. federal tax loss carryforward (“NOLs”) of approximately $1.1 billion, a state income tax loss carryforward of approximately $432.6 million. The regular U.S. federal income tax NOLs will expire in various amounts beginning in 2026 and ending in 2030.

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 2.7% and 3.3%). Any unused annual limitation may be carried over to subsequent years. The amount of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Income Taxes  – (continued)

limitation may, under certain circumstances, be increased by the built-in gains held by the Company at the time of the ownership change that are recognized in the five year period after the change. The Company experienced an ownership change on June 20, 2008, 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, 2013, 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 2012. The tax years ended June 30, 2010 through 2012 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 US cash income taxes due to the election to expense intangible drilling costs and 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. We presently do not expect to make any cash income tax payments during the upcoming fiscal year. If any such AMT payments were required, we believe that they would be recoverable against future regular income taxes due, with no expiration period. As such, we do not believe that any AMT payments would have a negative impact on earnings. We revise our ongoing estimated AMT obligation each quarter during the year.

We paid $12.9 million cash in US withholding taxes during the year as a result of payments of interest on indebtedness and management fees to our Bermuda entities. These withholding taxes are presented as separate line items in the effective tax rate reconciliation and payments expected in the coming fiscal year are presented as a current federal withholding obligation in the balance sheet.

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 35%, 32% and 61% of our total oil and natural gas revenues during the years ended June 30, 2013, 2012 and 2011, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 37%, 37% and 22% of our total oil and natural gas revenues during the years ended June 30, 2013, 2012 and 2011, respectively. J.P. Morgan Ventures Energy Corporation (“J.P. Morgan”) accounted for 12% and 18% of our total oil and natural gas revenues during the years ended June 30, 2013 and 2012, respectively. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Shell, ExxonMobil or J.P. Morgan curtailed their purchases.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Concentrations of Credit Risk  – (continued)

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.

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 of Notes to Consolidated Financial Statements in this Form 10-K.

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

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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.

During fiscal year 2013, we did not have any transfers from or to Level 3. 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,
	2013		2012		2013		2012
Assets:
Oil and natural gas derivatives					$	96,455	$	170,955
Liabilities:
Oil and natural gas derivatives					$	36,180	$	92,962
Restricted stock units	$	7,642	$	15,124
Time-based performance units		3,059		4,434
Total liabilities	$	10,701	$	19,558	$	36,180	$	92,962

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

	Level 3
	Year Ended June 30,
	2013			2012
Liabilities:
Performance-based performance units
Balance at beginning of year	$	22,855		$	20,305
Vested		(23,161	)		(23,807	)
Grants charged to income		7,084			26,357
Balance at end of year	$	6,778		$	22,855

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 19 — Prepayments and Accrued Liabilities

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

	June 30,
	2013		2012
Prepaid expenses and other current assets
Advances to joint interest partners	$	13,936	$	12,966
Insurance		31,258		30,515
Inventory		4,094		4,849
Royalty deposit		1,210		2,443
Stock held for future issuance to employees		23		8,786
Other		217		3,470
Total prepaid expenses and other current assets	$	50,738	$	63,029
Accrued liabilities
Advances from joint interest partners	$	1,348	$	301
Employee benefits and payroll		30,730		53,541
Interest payable		5,733		3,721
Accrued hedge payable		2,214		136
Undistributed oil and gas proceeds		47,766		54,484
Repurchase of company common stock		13,997		—
Other		3,404		6,635
Total accrued liabilities	$	105,192	$	118,818

Note 20 — Subsequent Events

In July 2013, we entered into a note to finance a portion of our Weather Based Insurance Linked Securities insurance premiums. The note is for a total face amount of $2.9 million and bears interest at an annual rate of 1.823%. The note amortizes over the remaining term of the insurance, which matures June 1, 2014.

On July 17, 2013, our Board of Directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of our common stock. The quarterly dividend will be paid on September 13, 2013 to shareholders of record on August 30, 2013.

On July 25, 2013, our equity method investee, M21K entered into a PSA Agreement with LLOG Exploration to acquire interests in certain oil and gas fields for $103 million. The closing of this acquisition is scheduled to occur on or before August 30, 2013.

In July 2013 we utilized a total of $21.2 million to repurchase 914,000 shares of our common stock at a weighted average price per share, excluding fees, of $23.19, after which, $156.1 million remains available for repurchase under the share repurchase program.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 21 — Selected Quarterly Financial Data — Unaudited

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

	Year Ended June 30, 2013
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter
Revenues	$	314,325	$	303,774	$	320,519	$	270,227
Operating income		111,747		99,870		93,537		56,651
Net income	$	62,053	$	40,436	$	41,332	$	18,260
Preferred stock dividends		2,873		2,873		2,874		2,876
Net income available for common stockholders	$	59,180	$	37,563	$	38,458	$	15,384
Net income per share attributable to common stockholders(1)
Basic	$	0.75	$	0.47	$	0.48	$	0.19
Diluted		0.72		0.46		0.47		0.19

	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 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

(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,
	2013			2012			2011
	(In Thousands)
Oil and Gas Activities
Exploration costs	$	168,512		$	183,397		$	98,133
Development costs		636,406			383,495			180,191
Total		804,918			566,892			278,324
Administrative and Other		11,187			3,778			2,909
Total capital expenditures		816,105			570,670			281,233
Property acquisitions
Proved		108,825			6,401			722,551
Unevaluated		52,339			—			289,711
Total acquisitions		161,164			6,401			1,012,262
Asset retirement obligations, insurance proceeds and other – net		(2,283	)		(55,399	)		205,702
Total costs incurred	$	974,986		$	521,672		$	1,499,197

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Oil and natural gas property costs excluded from the amortization base 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.

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

	June 30,
	2013		2012		2011
	(In Thousands)
Unevaluated properties	$	89,724	$	166,692	$	324,549
Wells in progress		332,827		252,068		142,744
	$	422,551	$	418,760	$	467,293

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 our reservoir engineers and audited by NSAI. 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 millions 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, 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 reserves		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)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Crude Oil (MBbls)			Natural Gas (MMcf)			Total (MBOE)
Proved reserves at June 30, 2012		84,793			208,990			119,624
Production		(10,318	)		(32,354	)		(15,710	)
Extensions and discoveries		40,690			40,714			47,476
Revisions of previous estimates		14,380			7,903			15,697
Reclassification of proved undeveloped		(1,123	)		(1,755	)		(1,416	)
Purchases of reserves		5,225			45,623			12,829
Proved reserves at June 30, 2013		133,647			269,121			178,500
Proved developed reserves
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
June 30, 2013		80,223			175,623			109,493
Proved undeveloped reserves
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
June 30, 2013		53,424			93,498			69,007

Our proved developed reserve estimates increased by 27.8 MMBOE or 34% to 109.5 MMBOE at June 30, 2013 from 81.7 MMBOE at June 30, 2012. The increase was primarily due to:

• Additions of 11.2 MMBOE from drilling, recompletions, and wells returned to production with major additions at South Timbalier 54: 2.9 MMBOE, Main Pass 61: 2.5 MMBOE, Grand Isle 16: 1.7 MMBOE, and West Delta 73: 1.2 MMBOE;

• Improved well performance of 22.3 MMBOE was realized with major upward revisions at West Delta 73: 9.4 MMBOE, South Timbalier 54: 6.2 MMBOE, South Pass 49: 4.4 MMBOE, and Main Pass 61: 1.3 MMBOE;

• Offset by a 1 MMBOE downward performance revision at Main Pass 73, and 15.7 MMBOE of production, and

• Acquisitions of 8.0 MMBOE at Bayou Carlin: 7.0 MMBOE and Vermilion 164: 1.0 MMBOE.

Our proved undeveloped reserve estimates increased by 31.1 MMBOE or 82% to 69.0 MMBOE at June 30, 2013 from 37.9 MMBOE at June 30, 2012. The increase was primarily due to:

• Additions of 36.3 MMBOE from identification of new proved undeveloped reserve locations were primarily at West Delta 73: 14.2 MMBOE, West Delta 30: 12.6 MMBOE, South Timbalier 54: 7 MMBOE, and Main Pass 61: 1.5 MMBOE;

• Acquisitions of 4.8 MMBOE at Vermilion 164: 3.3 MMBOE and West Delta 30: 1.5 MMBOE;

• Offset by 3.2 MMBOE of proved undeveloped reserves as of June 30, 2012 reserve report, which were converted to proved developed reserves and revised upward by 5.8 MMBOE in fiscal 2013. This resulted in a total of 9.0 MMBOE being converted to proved developed reserves during fiscal 2013 with the majority of the horizontal conversions at West Delta 73: 8.3 MMBOE. These proved undeveloped reserves were booked as directional/vertical in fiscal 2012 but we opted to drill these

110

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

locations as horizontals instead for higher production rates and ultimate recovery. The upward revision of 5.8 MMBOE in fiscal 2013 was a result of the higher realized initial production performance and higher estimated ultimate recovery from horizontals versus verticals, and

• 1.4 MMBOE of proved undeveloped reserves expired at South Timbalier 21: 0.4 MMBOE and South Pass 49: 1 MMBOE due to the five year development rule.

Two proved undeveloped reserve locations were not converted into proved developed reserves within the five year requirement and remain booked as proved undeveloped at June 30, 2013. Main Pass 61 OCS-G 16493 A-3 and Main Pass 73 B-19 ST are both proved undeveloped reserve locations to be sidetracked, but are still producing and cannot be drilled until the proved developed producing zone in each well depletes.

We expanded our internal effort on reserves evaluation, as we transitioned from third-party-evaluated to third-party-audited reserves. Our technical staff was increased by over 40%, many of whom were focused on field studies which identified a large number of new proved undeveloped reserve locations. These proved undeveloped reserve locations accounted for approximately 50% of our proved reserves increase. Our increased staffing level also enabled us to devote time to analyze and validate our proved developed reserves estimates utilizing multiple estimation techniques. As permitted under the existing guidance we employ techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. 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 internal reservoir engineers employed technologies on a by-well basis such as decline curve analysis (rate versus time, rate versus cumulative production, oil cut versus cumulative production and semi-log oil cut versus cumulative production) and where prudent, on a reservoir by-reservoir basis (material balance, volumetric analysis and analogy) that have been demonstrated to yield results with consistency and repeatability. Performance analysis including rate-time decline curves was utilized for reserve revisions to current wells and accounted for production techniques such as water flooding and gas-lifting that enhances and/or maintains production rates over time. Material balance methods were also employed for reserve revisions to current wells, incorporating production and pressure data to assist with reserve updates, particularly for wells and/or reservoirs with minimal production history and/or decline to-date. Further, in applying multiple techniques, we looked for consistency between methods rather than the highest or lowest result. We also used our knowledge of reservoir-specific drive mechanisms to identify which of the methods were most likely to be representative of the performance of the well. In some cases this gave lower reserves than rate-time, while in other cases it resulted in the same or higher reserves. On an average however, primarily due to the drive mechanisms in our reservoirs, higher reserves resulted from more appropriate selection of the reserves evaluation method.

We update and approve our long range plan on an annual basis, which includes our program to drill proved undeveloped locations. This plan is reflected in our reserve report at June 30, 2013 (the “June 30 Reserve Report”). We only recorded proved undeveloped reserves in our June 30 Reserve Report if they were scheduled to be developed within a five-year time horizon under the Company’s long range plan. We update our five year plan supporting our year-end fiscal results annually based upon long range criteria, including top value projects, maximization of present value and production volumes, drilling obligations, five year rule, and anticipated availability of certain rig types. However, the relative proportion of total proved undeveloped reserves that the Company develops over the next five years will not be uniform year to year, but will vary by year depending on several factors, including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells, and the inclusion of new acquisitions with associated proved undeveloped reserves.

In fiscal 2013, we converted 8.4% of our proved undeveloped reserves included in our June 30, 2012 reserve report. As scheduled in our long range plan that is reflected in the June 30 Reserve Report and further reflected in our initial budget for fiscal 2014, we expect to convert approximately 15% of our proved

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

undeveloped reserves during fiscal year 2014, 24% during fiscal year 2015, 27% during fiscal year 2016, 16% during fiscal year 2017 and 18% during fiscal year 2018.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows as of June 30, 2013 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $91.60 per barrel of oil (calculated using the unweighted average first-day-of-the-month West Texas Intermediate posted prices during the 12-month period ending on June 30, 2013). 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 $108.24 per barrel of oil and $43.64 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. The $108.24 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $91.60 per barrel (differential of $16.64 per barrel).

For natural gas, the average Henry Hub price used was $3.44 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 $3.63 per Mcf after adjusting for energy content, transportation fees, and regional price differentials.

The standardized measure of discounted future net cash flows related to proved oil and gas reserves as of June 30, 2013, 2012 and 2011 are as follows (in thousands):

	June 30,
	2013		2012		2011
Future cash inflows	$	15,048,978	$	10,009,119	$	7,989,182
Less related future
Production costs		3,657,595		2,737,969		2,188,918
Development and abandonment costs		1,838,159		1,304,007		1,184,728
Income taxes		2,591,351		1,377,363		1,073,278
Future net cash flows		6,961,873		4,589,780		3,542,258
Ten percent annual discount for estimated timing of cash flows		2,480,351		1,284,291		980,865
Standardized measure of discounted future net cash flows	$	4,481,522	$	3,305,489	$	2,561,393

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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,
	2013			2012			2011
Beginning of year	$	3,305,489		$	2,561,393		$	1,549,151
Revisions of previous estimates
Changes in prices and costs		(106,002	)		855,382			362,283
Changes in quantities		635,562			153,537			59,149
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		1,598,548			604,266			111,053
Purchases of reserves in place		480,111			—			1,553,858
Sales of reserves in place		—			—			(171,264	)
Accretion of discount		429,745			333,748			184,892
Sales, net of production and gathering and transportation costs		(842,268	)		(968,956	)		(604,057	)
Net change in income taxes		(676,158	)		(215,873	)		(476,319	)
Changes in rate of production		(456,254	)		(13,438	)		(72,069	)
Development costs incurred		125,925			24,519			114,710
Changes in abandonment costs and other		(13,176	)		(29,089	)		(49,994	)
Net change		1,176,033			744,096			1,012,242
End of year	$	4,481,522		$	3,305,489		$	2,561,393

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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 “Financial Statements and Supplementary Data” of this Form 10-K on page 73 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, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

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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.

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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		74
Consolidated Balance Sheets as of June 30, 2013 and 2012		76
Consolidated Statements of Income for the Years Ended June 30, 2013, 2012 and 2011		77
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended June 30, 2013, 2012 and 2011		78
Consolidated Statements of Stockholders’ Equity for the Years Ended June 30, 2013, 2012 and 2011		79
Consolidated Statements of Cash Flows for the Years Ended June 30, 2013, 2012 and 2011		80
Notes to Consolidated Financial Statements		81

(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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 21^st day of August 2013.

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 21, 2013
/s/ DAVID WEST GRIFFIN David West Griffin	Chief Financial Officer and (Principal Financial Officer and Principal Accounting Officer)	August 21, 2013
/s/ WILLIAM COLVIN William Colvin	Director	August 21, 2013
/s/ PAUL DAVISON Paul Davison	Director	August 21, 2013
/s/ DAVID M. DUNWOODY David M. Dunwoody	Director	August 21, 2013
/s/ CORNELIUS DUPRÉ II Cornelius Dupré II	Director	August 21, 2013
/s/ HILL A. FEINBERG Hill A Feinberg	Director	August 21, 2013
/s/ KEVIN S. FLANNERY Kevin S. Flannery	Director	August 21, 2013

117

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	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
10.1†	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
10.2†	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
10.3	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
10.4†	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
10.5†	Energy XXI Services, LLC Directors’ Deferred Compensation Plan	10.1 to Form 8-K filed on September 10, 2008	001-33628
10.6†	Employment Agreement of John D. Schiller, Jr., effective September 10, 2008	10.1 to Form 8-K filed on September 11, 2008	001-33628

118

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.7†	Separation Agreement of Steve Weyel, effective August 25, 2010	10.1 to Form 8-K filed on August 23, 2010	001-33628
10.8†	Employment Agreement of David West Griffin, effective September 10, 2008	10.3 to Form 8-K filed on September 11, 2008	001-33628
10.9†	Form of Indemnification Agreement between Energy XXI (Bermuda) Limited and Indemnitees	10.1 to Form 8-K filed on November 5, 2008	001-33628
10.10†	Form of Indemnification Agreement Between Company Subsidiaries and Indemnitees	10.2 to Form 8-K filed on November 5, 2008	001-33628
10.11†	Energy XXI Services, LLC Employee Stock Purchase Plan	10.1 to Form 8-K filed on November 5, 2008	001-33628
10.12†	Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan	4.2 to Form S-8 filed on June 10, 2009	333-159868
10.13†	Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Restricted Stock Unit Awards Agreement	10.20 to Form 10-K filed on August 9, 2012	001-33628
10.14*†	Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Performance Unit Awards Agreement
10.15†	Energy XXI Services, LLC, Employee Severance Plan (Amended and Restated August 11, 2010)	10.22 to Form 10-K filed on August 9, 2012	001-33628
10.16†	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
10.17	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
10.18	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
10.19	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

119

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.20	Third Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 19, 2012	10.1 to Form 8-K filed on October 15, 2012	001-33628
10.21	Fourth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of April 9, 2013	10.1 to Form 8-K filed on April 10, 2013	001-33628
10.22	Fifth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 1, 2013	10.1 to Form 8-K filed on May 6, 2013	001-33628
10.23	Energy XXI Services, LLC Restoration Plan Amended and Restated effective January 1, 2013	10.1 to Form 10-Q filed on January 31, 2013	001-33628
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.

120