10-K 1 v385304_10k.htm FORM 10-K

  

  

 

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, 2014

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   Smaller reporting company o
(Do not check if a smaller reporting company)     

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $925,761,391 based on the closing sale price of $27.06 per share as reported on The NASDAQ Global Select Market on December 31, 2013, 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, 2014 was 93,865,377.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2014 Annual Meeting of Shareholders, which will be filed within 120 days of June 30, 2014, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 


 
 

TABLE OF CONTENTS

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

    19  

Item 1B

Unresolved Staff Comments

    44  

Item 2

Properties

    44  

Item 3

Legal Proceedings

    44  

Item 4

Mine Safety Disclosures

    44  
           
PART II
 

Item 5

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

    45  

Item 6

Selected Financial Data

    47  

Item 7

Management’s Discussion and Analysis of Financial Condition and Results of Operations

    50  

Item 7A

Quantitative and Qualitative Disclosures About Market Risk

    70  

Item 8

Financial Statements and Supplementary Data

    73  

Item 9

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

    128  

Item 9A

Controls and Procedures

    128  

Item 9B

Other Information

    128  
PART III
 

Item 10

Directors, Executive Officers and Corporate Governance

    129  

Item 11

Executive Compensation

    129  

Item 12

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

    129  

Item 13

Certain Relationships and Related Transactions, and Director Independence

    129  

Item 14

Principal Accounting Fees and Services

    129  
           
PART IV
 

Item 15

Exhibits, Financial Statement Schedules

    130  
Signatures     137  

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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.

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

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

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

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

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).

Reserve acquisition cost.  The total consideration paid for an oil and natural gas property or set of properties, which includes the cash purchase price and any value ascribed to units issued to a seller adjusted for any post-closing items.

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 certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances and their potential effect on us. While management believes that these forward-looking statements are reasonable, such statements are not guarantees of future performance and the actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Company’s business or results. 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 Securities and Exchange Commission 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

Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries (“Energy XXI”, “us”, “we”, “our”, or “the Company”) is an independent oil and natural gas exploration and production company. 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 our 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”).

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 on the Gulf of Mexico Shelf (“GoM Shelf”). Energy XXI is the largest publicly traded independent operator on the GoM Shelf, operating seven of the largest GoM Shelf fields.

Since our inception in 2005, we have completed six major acquisitions for aggregate cash consideration of approximately $5.0 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 (“Pogo”) for approximately $415.1 million (the “Pogo Acquisition”). In November 2009, we acquired certain GoM 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 GoM Shelf oil and natural gas interests from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”). On June 3, 2014, we completed the acquisition of EPL Oil & Gas, Inc. (“EPL”) for approximately $2.5 billion, including the assumption of debt (the “EPL Acquisition”). The assets acquired in the EPL Acquisition are located on the GoM Shelf, which we expect to integrate with our existing portfolio on the GoM Shelf and provide significant near term cost savings. Please see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Form 10-K for detailed information on the EPL Acquisition.

Our acquisitions have been primarily oil-focused at an average reserve acquisition cost of approximately $21.35 per barrel of oil equivalent (“BOE”) and have provided us access to 767,445 net acres, ownership in 258 blocks, existing infrastructure to facilitate our growth and 16,036 square miles of 3D seismic data. We own and operate seven of the 15 largest GoM Shelf oil fields ranked by total cumulative oil production to date and utilize various techniques to increase the recovery factor to increase the total oil recovered. The techniques utilized by us include:

reviewing historical files to identify situations where partially depleted or overlooked reservoirs were determined to be uneconomic and abandoned in lower price environments but which now offer economic exploitation opportunities in a $100 per barrel oil price environment;
performing field studies, reservoir simulations and other analysis to identify previously overlooked, missed or under-appreciated opportunities to recover incremental oil reserves;
utilizing reprocessed 3D seismic and Wide Azimuth (“WAZ”) seismic data to better image near salt domes and improve production at existing wellbores and identify new opportunities where we can drill closer to salt domes to recover additional oil;
injecting water through dump floods or water injection wells to increase reservoir pressure and facilitate moving additional water through the reservoir to sweep incremental oil;

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drilling horizontal wells that enable us to recover a higher percentage of the original oil in place per well drilled versus a vertical well by providing for a more efficient sweep mechanism that minimizes water coning; and
optimizing gas lift and other standard production techniques to optimize recovery from existing wellbores.

The above techniques enable us to continually identify new oil weighted opportunities and maintain a large inventory of exploitation opportunities, while continuing to drill in these prolific large oil reservoirs.

Our geographic concentration on the GoM Shelf enables us to realize service cost synergies. By having operations in a geographically concentrated area, we can optimize helicopter and boat charters to more efficiently service our operations. In addition, our size provides us opportunities to place service work out to bid to obtain better services and prices.

As of June 30, 2014, our estimated net proved reserves were 246.2 MMBOE, of which 75% was oil and 61% was proved developed. Natural gas liquids comprised 5% of our oil reserves. Our current production is approximately 60,000 BOE per day, of which 69% is oil.

Business Strategy

Energy XXI’s goal is to grow and strengthen its position as the largest publicly traded independent operator on the GoM Shelf, with a focus on delivering value for our shareholders. We are focused on developing and exploring high quality oil-producing assets with low production decline rates.

We pursue growth opportunities through exploration and development drilling on our existing core properties to enhance production and ultimate recovery of reserves, supplemented by strategic acquisitions from time to time. Our acquisition strategy is to target mature, oil-producing properties on the GoM Shelf 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 drilling opportunities in our geographic area of expertise. We finance acquisitions with a combination of funds from our equity offerings, debt offerings, bank borrowings and cash generated from operations.

We plan to deploy a portion of our exploration budget to explore two play concepts on the GoM Shelf; namely the counter regional salt play and the ultra-deep play. We have acreage on 14 salt domes and are currently acquiring Full Azimuth Nodal (“FAN”) seismic data to identify potentially liquid-rich deep reservoirs around these salt domes. Existing facilities surrounding the properties may shorten cycle time from discovery to production as we believe we may be able to tie in new discoveries to existing infrastructure. Drilling around salt domes may commence as early as the first part of calendar year 2015. In the ultra-deep play, we are currently participating in eight projects. Certain of these projects are in various stages of activity as described below under “Ultra-Deep and Salt Play Activity.”

The EPL Acquisition significantly increased our enterprise value not only through the issuance of new common stock, but also significantly increased our indebtedness and debt to total capitalization percentage. Accordingly, our focus in the near term will be:

merging the two asset portfolios and high-grading our drilling inventory;
deploying capital resources on low-risk development drilling in the fields where we have previously enjoyed success;
reducing capital spending on exploration drilling and pursuing opportunities with third parties to have them participate in certain exploration projects with us;
continuing to de-risk our drilling program by focusing on execution through repeatable and predictable programs that will allow oil growth in core properties; and
maximizing cash flow to reduce leverage and pay down debt.

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Business Strengths

To effectively execute our business strategy, we have assembled a team of engineers with an average of 18 years of industry experience and a team of geologic and geophysical experts with an average of 33 years of industry experience. Our technical staff has specific expertise in developing our core properties. Additionally, the members of our senior management team average 31 years of operating experience on the GoM Shelf.

With the current prices of crude oil and significant technological advancements in drilling and completion techniques, we believe our high percentage of oil reserves compared to our overall reserve base provides us with an economic advantage and enhances shareholder value. Additionally, the production decline curve for oil in our GoM Shelf fields is typically lower than a comparable natural gas decline curve, resulting in longer term production of current reserves.

All our assets are located on the U.S. Gulf Coast or on the GoM Shelf and we currently operate 96% 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 costs of our projects.

General Information on Properties

Below are descriptions of our significant properties at June 30, 2014, which represent approximately 81% of our net proved reserves, and are ranked based on highest proved reserves as of June 30, 2014.

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 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 381 MMBOE. There are seven production platforms and 46 active wells located throughout the field. The field’s net production for the month of June 2014 of 4.6 MBOE/Day (“MBOED”) accounted for approximately 8% of our net production. Net proved reserves for the field, which is our largest field based upon net proved reserves, were 83% oil at June 30, 2014.

West Delta 27, 28, 29 and 30 blocks.  We operate and have a 100% working interest in the West Delta 27, 28, 29 and 30 blocks, located 21 miles offshore of Grand Isle, Louisiana in approximately 45 feet of water on the Outer Continental Shelf (“OCS”). Blocks 27, 28 and 29 were acquired through the EPL Acquisition. 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 via strong water drive. Minor faulting that is secondary to the major normal fault separates hydrocarbon accumulations into compartments. The field has produced in excess of 740 MMBOE. There are 39 production structures and 90 active wells located throughout the field. The field’s net production for the month of June 2014 of 9.0 MBOED accounted for approximately 15% of our net production. Net proved reserves for the field were 88% oil at June 30, 2014. This field is the largest oil field on the GoM Shelf, based on cumulative production to date.

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 57 MMBOE since production first began in 2002, from four Upper Miocene sands. The primary producer is the J-6 Sand, which consists of a series of stratigraphic traps, located along a regional south dip. The two larger J-6 Sand stratigraphic pods are oil reservoirs that are being waterflooded to maximize recovery. There are 26 producing wells and three major production platforms located throughout the field. The field’s net production for the month of June 2014 of 7.6 MBOED accounted for approximately 13% of our net production. Net proved reserves for the field were 84% oil at June 30, 2014.

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 the OCS. The field was originally discovered in 1955 by Humble Oil and Refining. The field is 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 combinations of

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structural and stratigraphic traps against salt at depth. Minor faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 146 MMBOE. There are six production platforms and 25 active wells located throughout the field. The field’s net production for the month of June 2014 of 4.4 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 73% oil at June 30, 2014.

Ship Shoal 208 Field.  We operate and have a 100% working interest in the Ship Shoal 208 Field, located 110 miles southwest of New Orleans, Louisiana in approximately 100 feet of water on OCS blocks Ship Shoal 208, 209 and 215. The field was acquired through the EPL Acquisition. The Ship Shoal 208 Field surrounds a large salt dome and produces from over 30-Upper Pliocene through Upper Miocene reservoirs. The field was discovered by Kerr-McGee Corporation in 1961 and has produced in excess of 221 MMBbls and 1,300 BCF since production first began in 1963. We have 11 platforms and 27 active wells throughout the field. The field’s net production for the month of June 2014 of 4.4 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 67% oil at June 30, 2014.

South Pass 49 Field.  We operate and have a 100% working interest in the South Pass 49 field, which is located near the mouth of the Mississippi River in approximately 400 feet of water. Additional interest in the field was acquired through the EPL Acquisition. The field was discovered by Gulf Oil in 1974. The field produces from Lower Pliocene sands, which consist of the Discorbis 20 thru Discorbis 70 sands, ranging in depths from 7,600 feet to 9,400 feet, on OCS blocks South Pass 33, 48, and 49 which have 15 active wells located throughout the field. The field is produced from one central production platform and has produced in excess of 118 MMBOE. The field’s net production for the month of June 2014 of 4.0 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 59% oil at June 30, 2014.

South Pass 78.  We operate the South Pass 78 complex and own a working interest of 100% of the acreage position in this area. Additional interest in the field was acquired through the EPL Acquisition. The complex is located 86 miles southeast of New Orleans. It contains 23 producing wells in water depths ranging from approximately 140 to 190 feet in four lease blocks. The field was discovered in 1972 by Pennzoil Energy Co. and has produced in excess of 237 MMBOE. There are four major production platforms, three of which have producing wells, located throughout the field. The field’s net production for the month of June 2014 of 1.9 MBOED accounted for approximately 3% of our net production. Net proved reserves for the field were 60% oil at June 30, 2014.

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 began 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 523 MMBOE. There are 13 production platforms and 57 active wells located throughout the field. The field’s average net production for the month of June 2014 of 4.4 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 78% oil at June 30, 2014. This field is the fifth largest oil field on the GoM Shelf.

South Timbalier 21.  We operate and have a 100% working interest in the South Timbalier 21 area, located six to ten miles offshore of Lafourche Parish, Louisiana in approximately 55 feet of water on OCS blocks South Timbalier 21, 22, 23, 26, 27, 28 and 41, as well as on two state leases. Block 41 was acquired through the EPL Acquisition. The South Timbalier 21 area, discovered by Gulf Oil Company and Shell Oil Company in the late 1950s and 1960s, has produced in excess of 512 MMBOE since production began in 1957 with the exception of South Timbalier 41, discovered by Energy Partners in 2004, which has produced in excess of 24 MMBOE. 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. A large counter-regional fault, along with salt and smaller faults, creates traps and separates hydrocarbon accumulations into individual compartments. There are 20 major production platforms and 56 smaller structures located throughout the fields and 66 active wells. The area’s net production for the month of June 2014 of 3.3 MBOED accounted for approximately 6% of our net production. Net proved reserves for the field were 88% oil at June 30, 2014. This field is the fourth largest oil field on the GoM Shelf.

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East Bay.  We operate this field and own an average 96% working interest in our acreage position in this area. The field includes the South Pass 24 and 27 fields and is located 89 miles southeast of New Orleans, near the mouth of the Mississippi River. The field was acquired through the EPL Acquisition. It contains 197 producing wells located along the coastline and in water depths up to approximately 70 feet. The field was discovered by Shell in the early 1950s and has produced over 900 MMBOE to date. Over 1,400 wells have been drilled to develop approximately 70 hydrocarbon bearing sands. The field is divided by a major east-west fault with South Pass 24 field being on the north or up thrown side of the fault and South Pass 27 field being on the south or down thrown side of the fault. Producing depths vary from a few thousand feet to over 13,000 feet true vertical depth (“TVD”). The field’s net production for the month of June 2014 of 2.2 MBOED accounted for approximately 4% of our net production. Net proved reserves for the field were 95% oil at June 30, 2014.

Ultra-Deep and Salt Play Activity

Our partnership with the operator Freeport McMoRan Oil and Gas, LLC (formerly McMoRan Exploration Company and now acquired by Freeport-McMoRan, Inc.) retains a leading acreage position in the emerging Inboard Lower Tertiary and Cretaceous gas trend, located in the GoM Shelf and onshore South Louisiana. We have participated in eight projects to date, both offshore and onshore, with our participations ranging from approximately 9% to 20%. This emerging exploration trend focuses on the subsalt Lower Wilcox and Cretaceous sections. The Lomond North well is in the process of being completed and the Davy Jones No. 2 well was determined to be non-commercial in the Tuscaloosa sand and awaiting test of Wilcox sands.

In our joint venture with Fieldwood Energy, LLC (“Fieldwood”) and Apache Corporation (“Apache”) in the Main Pass area, we have drilled two wells on the Main Pass 295 structure. The #1 BP1 well was drilled to a depth of 19,555 feet MD/19,510 feet TVD on the southern flank of the salt dome, penetrating eight oil sands and one gas-bearing sand. An offset well, the MP 295 #3, was drilled to a depth of 10,561 feet MD/10,332 feet TVD and also has encountered multiple hydrocarbon-bearing sands. Both wellbores have been suspended for future use. This joint venture is expecting 3D-WAZ seismic data analysis to be completed in January 2015.

We are currently negotiating an extension of our joint venture with ExxonMobil in the Vermilion area with a plan to reprocess 3D seismic data during 2014 to help determine future drilling activity.

Reserve Estimation Procedures and Internal Controls over Reserve Estimates

For fiscal year 2014, proved reserves were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”) as described in further detail under “Third Party Reserves Audit” below.

Our internal controls policies over recording of reserves estimates require reserves to be in compliance with the definitions and regulations for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent Securities and Exchange Commission (“SEC”) staff interpretations and guidance and conform to the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas. Our internal controls over reserves estimates include, but are not limited to the following:

NSAI is engaged by the Board of Directors Audit Committee (“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;
Prior to final reserves report issuance, the Board of Directors meets with a NSAI representative to review material variances, if any, between NSAI’s estimates and the Company’s estimates and to discuss any issues with the reserves evaluation process;
Lease operating statements of the previous twelve months are analyzed to determine actual historical expenses and realized prices to be used in the economic analysis. Data entered into the reserves database is checked against data determined by the lease operating statement analysis;
Updated capital costs are supplied by our Operations and Drilling Departments and entered by our reservoir engineers;

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Internal reserves estimates are prepared by the area asset reservoir engineers and reviewed by the asset team management;
Ownership, working interest and net revenue interest, used in the net reserves calculation are compared against the Well Master to ensure accuracy;
Proved undeveloped properties scheduling is checked for consistency with the Company’s budget and long range plan which demonstrate the Company’s commitment to develop those locations;
Material reserve variances are reviewed and approved by the Director of Reserves and Business Planning, or his designates, to ensure compliance and accuracy;
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;
All reserves estimates have appropriate back-up documentation;
Reserve estimates are finally reviewed and approved by our Director of Reserves and Business Planning and certain members of senior management;
The Audit Committee reviews significant reserve changes on an annual basis.

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 29 years of industry experience with positions of increasing responsibility. The Director of Reserves and Business Planning directly reports to our Chief Financial Officer.

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and 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-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Connor B. Riseden and Mr. Shane M. Howell. Mr. Riseden has been practicing consulting petroleum engineering at NSAI since 2006. Mr. Riseden is a Licensed Professional Engineer in the State of Texas (No. 100566) and has over 12 years of practical experience in petroleum engineering, with over 12 years’ experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 2001 with a Bachelor of Science Degree in Petroleum Engineering and from Tulane University in 2005 with a Master of Business Administration Degree. Mr. Howell has been practicing consulting petroleum geology at NSAI since 2005. Mr. Howell is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 11276) and has over 15 years of practical experience in petroleum geosciences, with over 9 years’ experience in the estimation and evaluation of reserves. He graduated from San Diego State University in 1997 with a Bachelor of Science Degree in Geological Sciences and in 1998 with a Master of Science Degree in Geological Sciences. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The technical work was conducted by a team of 11 NSAI petroleum engineers and geoscientists having an average industry experience of 22 years.

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” is defined by the SEC as “much more likely to be produced than not” and “much more likely to increase or remain constant than to decrease.” Our internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies 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, pressure data and reservoir simulation.

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Third-Party Reserves Audit

The estimate of reserves disclosed in this Form 10-K for fiscal 2014 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. NSAI audited 100% of our proved reserves.

NSAI prepared its own estimates of our proved reserves by using the data and documentation with which we used to prepare our own estimates. They then compare their estimates to ours for reasonableness. NSAI also examined our 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 conducting 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 Rule 4-10(a)(24) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves as of June 30, 2014, based upon their evaluation concluding 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 letter is attached as Exhibit 99.1 to this Form 10-K.

Summary of Oil and Gas Reserves at June 30, 2014

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 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, 2014
Based on Average Fiscal-Year Prices
     Oil MMBbls   NGLs MMBbls   Natural Gas
Bcf
  MMBOE   Percent of
Total Proved
  PV-10
(in thousands)(1)
Proved
                                                     
Developed     106.9       5.9       222.9       149.9       61 %    $ 4,267,430  
Undeveloped     68.9       3.7       142.0       96.3       39 %      3,334,074  
Total Proved     175.8       9.6       364.9       246.2                 7,601,504  
Future Income taxes                                                  2,546,155  
Less 10% discount                                   892,176  
Future income taxes discounted at 10%                                   1,653,979  
Standardized measure of future discounted net cash flows                                 $ 5,947,525  

(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

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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, 2014) used in determining future net revenues were $96.75 per barrel of oil for West Texas Intermediate benchmark plus $7.05 per barrel for crude quality and location differentials, for a total of $103.80 per barrel. For NGL’s, the average price used was $42.10 per barrel. For natural gas, the average price used was $4.10 per MMBtu.

Changes in Proved Reserves

Our proved developed reserve estimates increased by 40.4 MMBOE or 37% to 149.9 MMBOE at June 30, 2014 from 109.5 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 52.3 MMBOE, primarily in the EPL Acquisition.
Additions of 5.4 MMBOE from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from the 4 fields: West Delta 30, Main Pass 61, Main Pass 73 and Grand Isle 16.

Offset by:

Downward revision of 2.7 MMBOE, mainly due to lower than forecasted per well throughput at West Delta 73 and sanding issues at South Timbalier 54, offset by positive performance revision at West Delta 30 and South Pass 49
Divestiture of 4.7 MMBOE, and
Production of 16.4 MMBOE.

Our proved undeveloped reserve estimates increased by 27.3 MMBOE or 40% to 96.3 MMBOE at June 30, 2014 from 69.0 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 24.6 MMBOE, primarily in the EPL Acquisition.
Additions of 15.1 MMBOE, primarily additional drilling locations to make up for the lower throughput per well in West Delta 73, replacement locations for South Timbalier 54 and from identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 61.

Offset by:

Downward revision of 5.9 MMBOE, primarily due to lease expiration in South Fresh Water Bayou, reallocation of reserves due to new information from the drilling program in Main Pass 61, and change of fluid type due to new information from the drilling program in West Delta 30.
Conversion of 6.6 MMBOE from proved undeveloped to proved developed reserves.

Development of Proved Undeveloped Reserves

Our proved undeveloped (“PUD”) reserves at June 30, 2014 were 96.3 MMBOE. Future development costs associated with our PUD reserves at June 30, 2014 totaled approximately $1,430 million. In the fiscal year ended June 30, 2014, we developed approximately 9.5% of our PUD reserves included in our June 30,

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2013 reserve report, consisting of 18 gross, 18 net wells at a net cost of approximately $160.9 million. In addition, we also spent $101.7 million in developing PUD reserves that were still in progress at the end of the fiscal year ended June 30, 2014.

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 newly acquired proved undeveloped reserves. As scheduled in our long range plan, all of our PUD locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our report, with the exception of two. These two locations are to be sidetracked from existing wellbores which are still producing economically, thus cannot be drilled until the proved developed producing zones deplete.

The following table discloses our progress toward the development of PUD reserves during the fiscal year ended June 30, 2014.

   
  Oil and
Natural Gas
  Future Development Costs
     (MBOE)   (In thousands)
Proved undeveloped reserves at June 30, 2013     69,007     $ 1,039,918  
Extensions and discoveries     15,072       315,375  
Revisions of previous estimates     (6,183 )      4,966  
Changes in prices and costs     314       10,465  
Purchases of reserves in place     24,627       307,632  
Conversions to proved developed reserves     (6,581 )      (247,865 ) 
Total proved undeveloped reserves added     27,249       390,573  
Proved undeveloped reserves at June 30, 2014     96,256     $ 1,430,491  

Drilling Activity

The following table sets forth our drilling activity for the three years ended June 30, 2014, 2013 and 2012:

           
  Year Ended June 30,
     2014   2013   2012
     Gross   Net   Gross   Net   Gross   Net
Productive wells drilled
                                                     
Development     12       12       23.0       19.7       13.0       10.4  
Exploratory                 1.0       0.1              
Total     12       12       24.0       19.8       13.0       10.4  
Nonproductive wells drilled
                                                     
Development                 3.0       3.0       1.0       0.1  
Exploratory     1       1       3.0       2.2       2.0       1.3  
Total     1       1       6.0       5.2       3.0       1.4  

Present Activities

As of June 30, 2014, 11 gross wells, representing approximately 8.5 net wells, were being drilled.

Delivery Commitments

We had no delivery commitments in the three years ended June 30, 2014.

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Productive Wells

Our working interests in productive wells at June 30, 2014, and 2013 were as follows:

       
  June 30,
     2014   2013
     Gross   Net   Gross   Net
Natural Gas     176       137       91       51  
Crude Oil     808       713       372       284  
Total     984       850       463       335  

Acreage

Working interests in developed and undeveloped acreage at June 30, 2014 were as follows:

           
  June 30, 2014
     Developed Acres   Undeveloped Acres   Total Acres
     Gross   Net   Gross   Net   Gross   Net
Onshore     37,279       36,206       131,652       46,012       168,931       82,218  
Offshore     555,084       396,748       590,241       288,479       1,145,325       685,227  
Total     592,363       432,954       721,893       334,491       1,314,256       767,445  

The following table summarizes potential expiration of our onshore and offshore undeveloped acreage for the years ending June 30, 2015, 2016 and 2017.

           
  Year Ending June 30,
     2015   2016   2017
     Gross   Net   Gross   Net   Gross   Net
Onshore     17,150       12,334       55,845       22,758       30,676       5,405  
Offshore     87,651       25,465       23,040       7,200       20,603       20,603  
Total     104,801       37,799       78,885       29,958       51,279       26,008  

Capital Expenditures, Including Acquisitions and Costs Incurred

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

     
  Year Ended June 30,
     2014   2013   2012
     (In Thousands)
Property acquisitions
                          
Proved   $ 2,046,879     $ 108,825     $ 6,401  
Unevaluated     924,882       52,339        
Exploration costs     153,136       168,512       183,397  
Development costs     632,262       633,868       327,360  

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Oil and Natural 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,
     2014   2013   2012
Sales Volumes per Day
                          
Natural gas (MMcf)     89.7       88.6       81.5  
NGLs (MBbls)     2.4       2.3       2.8  
Crude oil (MBbls)     27.7       26.0       27.7  
Total (MBOE)     45.0       43.1       44.1  
Percent of BOE from crude oil and NGLs     67 %      66 %      69 % 
Average Sales Price
                          
Natural gas per Mcf   $ 4.15     $ 3.48     $ 2.97  
Hedge gain per Mcf     0.11       0.47       0.94  
Total natural gas per Mcf   $ 4.26     $ 3.95     $ 3.91  
NGLs per Bbl   $ 40.78     $ 38.38     $ 53.73  
Crude oil per Bbl   $ 105.86     $ 109.12     $ 111.41  
Hedge gain (loss) per Bbl     (1.28 )      1.40       0.04  
Total crude oil per Bbl   $ 104.58     $ 110.52     $ 111.45  
Sales price per BOE   $ 75.44     $ 75.14     $ 78.97  
Hedge gain (loss) per BOE     (0.56 )      1.81       1.77  
Total sales price per BOE   $ 74.88     $ 76.95     $ 80.74  

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

The following field contains 15% or more of our total proved reserves as of June 30, 2014. Our average daily production, average sales prices and production costs follow:

     
  Year Ended June 30,
     2014   2013   2012
West Delta 73
                          
Sales Volumes per Day
                          
Natural gas (MMcf)     7.5       9.0       6.0  
NGLs (MBbls)     0.1       0.1       0.1  
Crude oil (MBbls)     4.1       3.5       2.3  
Total (MBOE)     5.5       5.1       3.4  
Percent of BOE from crude oil and NGLs     75 %      71 %      71 % 
Average Sales Price
                          
Natural gas per Mcf   $ 4.22     $ 3.46     $ 1.67  
NGLs per Bbl   $ 40.74     $ 33.50     $ 61.18  
Crude oil per Bbl   $ 105.06     $ 109.11     $ 111.33  
Production Costs per BOE   $ 19.76     $ 18.54     $ 21.30  

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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,
     2014   2013   2012
Average Costs per BOE
                          
Production costs
                          
Lease operating expense
                          
Insurance expense   $ 1.90     $ 2.08     $ 1.77  
Workover and maintenance     4.04       4.15       3.49  
Direct lease operating expense     16.31       15.23       13.99  
Total lease operating expense     22.25       21.46       19.25  
Production taxes     0.33       0.33       0.45  
Total production costs   $ 22.58     $ 21.79     $ 19.70  
Gathering and transportation   $ 1.43     $ 1.54     $ 1.01  
Depreciation, depletion and amortization rates   $ 25.75     $ 23.95     $ 22.76  

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 may enter into hedging arrangements to minimize commodity downside exposure. Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges and expect to carry those hedges through the end of contract term beginning from June 2014 through December 2015. 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 costs. 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 45%, 35% and 32% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. ExxonMobil accounted for approximately 43%, 37% and 37% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. J.P. Morgan Ventures Energy Corporation 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 or ExxonMobil curtailed their purchases.

We transport a portion of our oil and natural 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.

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

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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 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,

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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. FERC’s civil penalty authority under EPAct 2005 applies to violations of Order 704.

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.

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

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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 Bureau of Safety and Environmental Enforcement (“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 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.

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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; and
Safe Drinking Water Act, which governs underground injection and disposal activities; and U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.

We 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.

Oil Pollution Act.  The Oil Pollution Act of 1990 (“OPA”) and regulations adopted pursuant to OPA impose a variety of requirements on “responsible parties” related to the prevention of and response to oil spills into waters of the United States, including the OCS. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA subjects owners of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and a variety of public and private damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages. Although defenses exist to the liability imposed by OPA, they are limited. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to

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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”). Among the EPA’s rules regulating greenhouse gas emissions under the CAA, one requires a reduction in emissions of greenhouse gases from motor vehicles and another regulates emissions of greenhouse gases from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries and certain onshore and offshore oil and natural gas production facilities.

In addition, the U.S. 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.

Employees

We had 497 employees at June 30, 2014, none of which were 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 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, therefore there is 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 price per barrel for the period between January 1, 2014 and June 30, 2014 ranged from a high of $107.26 to a low of $91.66 and the NYMEX natural gas price per MMBtu for the period January 1, 2014 to June 30, 2014 ranged from a high of $6.15 to a low of $4.01. 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, 2014 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, 2014, we were not required to reduce any proved reserve estimates due to the five year development rule.

As of June 30, 2014, approximately 39% of our total proved reserves were undeveloped and approximately 15% 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 of approximately 1% 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 GoM 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 Gulf of Mexico properties subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

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

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Our offshore operations 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 four deepwater fields, Viosca Knoll 822/823, Viosca Knoll 821, Viosca Knoll 1003 and Mississippi Canyon 248. The Mississippi Canyon 248 field was acquired in the EPL Acquisition. We may evaluate additional activity in the deepwater Gulf of Mexico in the future. Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.

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

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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.

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 96% 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;

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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 two customers.

Shell and ExxonMobil each accounted for approximately 45% and 43% of our total oil and natural gas revenues during the year ended June 30, 2014, respectively. Our inability to continue to sell our production to Shell or ExxonMobil, if not offset by sales with new or other existing customers, could have a material adverse effect on our business and operations.

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

We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated or the decommissioning be accelerated, such as can happen after a hurricane, such costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations.

Lower oil and gas prices and other factors 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.

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Write-downs may be required in the full cost ceiling and goodwill recorded in connection with our oil and natural gas properties acquisition 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, estimated 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.

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;

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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.

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

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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 six major acquisitions and have become a reporting company in the U.S. Most recently, on June 3, 2014, we completed the acquisition of EPL. We expect to incur substantial expenses in connection with the integration of Energy XXI and EPL. There are a large number of processes, policies, procedures, operations, technologies and systems that must be integrated, including purchasing, accounting and finance, sales, billing, payroll, pricing, revenue management, maintenance, marketing, payments triggered by change in control provisions and benefits. While Energy XXI and EPL have assumed that a certain level of expenses would be incurred, there are many factors beyond their control that could affect the total amount or the timing of the integration expenses. Moreover, many of the expenses that will be incurred are, by their nature, difficult to estimate accurately. These expenses could, particularly in the near term, exceed the savings that the combined company expects to achieve from the elimination of duplicative expenses and the realization of economies of scale and cost savings. These integration expenses likely will result in the combined company taking significant charges against earnings following the completion of the EPL Acquisition.

Future transactions may also 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 or businesses 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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For example, the EPL Acquisition involves the integration of two companies that had operated independently. The success of the EPL Acquisition will depend, in large part, on our ability to realize the anticipated benefits, including synergies, cost savings, innovation and operational efficiencies, from combining the businesses of Energy XXI and EPL. To realize these anticipated benefits, the businesses of Energy XXI and EPL must be successfully integrated. This integration will be complex and time-consuming. The failure to integrate successfully and to manage successfully the challenges presented by the integration process may result in the combined company not achieving the anticipated benefits of the EPL Acquisition.

Potential difficulties that may be encountered in the integration process include the following:

the inability to successfully integrate the businesses of Energy XXI and EPL in a manner that permits the combined company to achieve the full benefit of synergies, cost savings and operational efficiencies that are anticipated to result from the EPL Acquisition;
complexities associated with managing the larger, more complex, combined business;
complexities associated with integrating the workforces of the two companies;
potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the EPL Acquisition, including one-time cash costs to integrate the two companies that may exceed the anticipated range of such one-time cash costs that Energy XXI and EPL estimated as of the date of execution of the EPL Acquisition Agreement;
difficulty or inability to refinance the debt of the combined company or comply with the covenants thereof;
performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the EPL Acquisition and integrating the companies’ operations; and
the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.

Any of these difficulties in successfully integrating the businesses of Energy XXI and EPL, or any delays in the integration process, could adversely affect our ability to achieve the anticipated benefits of the EPL Acquisition and could adversely affect our business, financial results, financial condition and stock price. Even if we are able to integrate the business operations of Energy XXI and EPL successfully, there can be no assurance that this integration will result in the realization of the full benefits of synergies, cost savings, innovation and operational efficiencies that we currently expect from this integration or that these benefits will be achieved within the anticipated time frame.

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 current and 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.

For example, following the EPL Acquisition, our size increased significantly beyond the size of either Energy XXI’s or EPL’s business prior to the EPL Acquisition. Our future success depends, in part, upon our ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. There can be no assurances that we will be successful or that we will realize the expected operating efficiencies, cost savings, revenue enhancements and other benefits currently anticipated from the EPL Acquisition.

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

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

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

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

acceptable prices for available properties;
amounts of recoverable reserves;
estimates of future oil and natural gas prices;
estimates of future exploratory, development and operating costs;
estimates of the costs and timing of plugging and abandonment; and
estimates of potential environmental and other liabilities.

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

Risks Related to Our Indebtedness and Access to Capital and Financing

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

As of June 30, 2014, we had total indebtedness of $3,760 million. Our leverage and the current and future restrictions contained in the agreements governing our indebtedness may reduce our ability to incur additional indebtedness, engage in certain transactions or capitalize on acquisition or other business opportunities. Our indebtedness and other financial obligations and restrictions could have financial consequences. For example, they could:

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

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increase our vulnerability to general adverse economic and industry conditions;
result in higher interest expense in the event of increases in interest rates since some of our debt is at variable rates of interest;
have a material adverse effect if we fail to comply with financial and restrictive covenants in any of our debt agreements, including an event of default if such event is not cured or waived;
require us to dedicate a substantial portion of future cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate requirements;
limit our flexibility in planning for, or reacting to, changes in our business and industry; and
place us at a competitive disadvantage to those who have proportionately less debt.

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

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

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the indentures governing our senior notes and our revolving credit facility do not fully prohibit us or our subsidiaries from doing so. At June 30, 2014, we and our subsidiaries collectively had approximately $716.1 million of secured indebtedness and $3.0 billion of other indebtedness. If new debt or liabilities are added to our current debt level, the related risks that we now face could increase.

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

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

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

refinance all or a portion of our debt;
obtain additional financing;
sell some of our assets or operations;
reduce or delay capital expenditures, research and development efforts and acquisitions; or
revise or delay our strategic plans.

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

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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 certain payment obligations;
incur indebtedness and issue preferred stock; and
sell or otherwise dispose of assets, including capital stock of subsidiaries.

The existence of these covenants may prevent or delay us from pursuing business opportunities that we believe would otherwise benefit us. For example, as of June 30, 2014, EGC anticipates it may not have been in compliance with the total leverage ratio covenant included within Section 7.2.4(a) of the First Lien Credit Agreement, which requires EGC to maintain a Total Leverage Ratio (as defined therein) of not more than 3.5 to 1.0 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC’s leverage ratio was 3.6 to 1.0 for the quarter ended June 30, 2014. EGC received a waiver from the lenders under the First Lien Credit Agreement on August 22, 2014 with respect to this violation for the quarters ending June 30, 2014 and September 30, 2014. The waiver is conditioned upon EGC maintaining a Total Leverage Ratio of not more than 4.25 to 1.00 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC was in compliance with the requirements under the waiver for the fiscal quarter ended June 30, 2014 and expects to be in compliance therewith for the fiscal quarter ended September 30, 2014. EGC is currently in discussions with the lenders under the First Lien Credit Agreement to amend certain of the financial covenants in order to ensure that EGC will be in compliance with the covenants for the remainder of the 2015 fiscal year. There is no assurance that EGC will reach agreement with its lenders on these amendments. In the event an amendment cannot be obtained, EGC may need to take certain actions within its control in order to comply with the current covenants.

In addition, 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.

The indenture governing the 8.25% senior notes due 2018 includes restrictive covenants, which could adversely affect the future business and operations of the combined company.

The covenants included in the indenture governing the 8.25% senior notes due 2018 (“8.25% Senior Notes”) that EGC assumed in the EPL Acquisition include certain restrictive covenants that provide less operational flexibility than the covenants governing our other outstanding indebtedness. In the event that we are unable to obtain the requisite consents for an amendment or are unable to replace or refinance the 8.25% Senior Notes, the notes’ restrictive covenants could make it more difficult to integrate the operations of Energy XXI and EPL and operate the combined company in the most efficient manner. Our failure in this regard could adversely affect our future business and operations.

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.

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

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

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

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

As of June 30, 2014, we had borrowed $689 million and had $225.7 million in letters of credit issued under our revolving credit facility and our borrowing base was $1.5 billion. We expect that the next determination of the borrowing base under our revolving credit facility will occur in the fall of 2014. 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.

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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 $1.5 billion. 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 of obtaining financing from the credit markets increased as many lenders and institutional investors 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. In recent years, access to capital has significantly improved and the cost of raising money in the debt capital markets has been near all-time lows. However, a return to the conditions seen during and after the crisis 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

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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 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.

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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.

Under certain environmental laws that impose strict, joint and several liability, we could be held liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, and regardless of whether current or prior operations were conducted in compliance with all applicable laws and consistent with accepted standards of practice at the time those actions were taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. 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.

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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, federal authorities have pursued a series of regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. The federal government, acting through the U.S. Department of the Interior (“DOI”) and its implementing agencies that have since evolved into the present day BOEM and the BSEE, have issued various rules, Notices to Lessees and Operators (“NTLs”), and temporary drilling moratoria imposing new regulatory requirements and environmental and safety measures upon exploration, development and production operators in the Gulf of Mexico. 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.
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.

These regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration and production plan reviews, develop drilling applications, and apply for and receive new well permits. 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. In addition, we could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the Gulf of Mexico if we fail to comply with these requirements. Moreover, if oil spill incidents similar to the April 2010 Deepwater Horizon incident were to occur in the future in areas where we conduct operations, the United States or other countries could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue safety and environmental regulatory initiatives regarding offshore oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on our volume of business, our financial position, our results of operations, and liquidity.

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Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations include the U.S. Gulf of Mexico.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations are many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the U.S. Gulf of Mexico following the DOI’s issuance of an NTL, effective October 2010, that established a more stringent regimen for the timely decommissioning of what is known as “idle iron” wells, platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease in the U.S. Gulf of Mexico. Historically, many oil and natural gas producers in the Gulf of Mexico have delayed the plugging, abandoning or removal of idle iron until they met the final decommissioning regulatory requirement, which has been established as being within one year after the lease expires or terminates, a time period that sometimes is years after use of the idle iron has been discontinued. The idle iron NTL establishes new triggers for commencing decommissioning activities — any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years’ time. Plugging or abandonment of wells may be delayed by two years if all of such wells’ hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. Moreover, as a result of the implementation of this NTL, there is expected to be increased demand for salvage contractors and equipment operating in the U.S. Gulf of Mexico, resulting in increased estimates of plugging, abandonment and removal costs and associated increases in operators’ asset retirement obligations.

Lastly, it is expected that a new NTL related to the requirements for an exemption from supplemental bonding will be issued in late 2014 or early 2015 which is expected to impact the eligibility to receive a supplemental bonding waiver.

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.

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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 (“CAA”). Among the EPA’s rules regulating greenhouse gas emissions under the CAA, one requires a reduction in emissions of greenhouse gases from motor vehicles and another regulates emissions of greenhouse gases from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries and certain onshore oil and natural gas production facilities.

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

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The 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 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

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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 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. In addition, many governmental agencies have increased regulatory oversight and permitting requirements in recent years. We may not be able to obtain all necessary permits and approvals or obtain them in a timely manner, and as a result our operations may be adversely affected. In addition, obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals, future changes to these permits or approvals, or any adverse changes in the interpretation of existing permits and approvals, and these 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.

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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, among other proposed legislation, 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.

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

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

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.

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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 Co-operation 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).

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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.

Litigation Related to the Merger

In March and April, 2014, three alleged EPL stockholders (the “plaintiffs”) filed three separate class action lawsuits in the Court of Chancery of the State of Delaware on behalf of EPL stockholders against EPL, its directors, Energy XXI, Energy XXI Gulf Coast, Inc., a Delaware corporation and an indirect wholly owned subsidiary of Energy XXI (“OpCo”), and Clyde Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of OpCo (“Merger Sub” and collectively, the “defendants”). The Court of Chancery of the State of Delaware consolidated these lawsuits on May 5, 2014. The consolidated lawsuit is styled In re EPL Oil & Gas Inc. Shareholders Litigation, C.A. No. 9460-VCN, in the Court of Chancery of the State of Delaware (the “lawsuit”).

Plaintiffs allege a variety of causes of action challenging the Agreement and Plan of Merger between Energy XXI, OpCo, Merger Sub, and EPL (the “merger agreement”), which provides for the acquisition of EPL by Energy XXI. Plaintiffs allege that (a) EPL’s directors have allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL have allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs’ causes of action are based on their allegations that (i) the merger allegedly provided inadequate consideration to EPL stockholders for their shares of EPL common stock; (ii) the merger agreement contains contractual terms — including, among others, the (A) “no solicitation,” (B) “competing proposal,” and (C) “termination fee” provisions — that allegedly dissuaded other potential acquirers from making competing offers for shares of EPL common stock; (iii) certain of EPL’s officers and directors allegedly received benefits — including (A) an offer for one of EPL’s directors to join the Energy XXI board of directors and (B) the triggering of change-in-control provisions in notes held by EPL’s executive officers — that were not equally shared by EPL’s stockholders; (iv) Energy XXI required EPL’s officers and directors to agree to vote their shares of EPL common stock in favor of the merger; and (v) EPL provided, and Energy XXI obtained, non-public information that allegedly allowed Energy XXI to acquire EPL for inadequate consideration. Plaintiffs also allege that the Registration Statement filed on Form S-4 by EPL and Energy XXI on April 1, 2014 omits information concerning, among other things, (i) the events leading up to the merger, (ii) EPL’s efforts to attract offers from other potential acquirors, (iii) EPL’s evaluation of the merger; (iv) negotiations between EPL and Energy XXI, and (v) the analysis of EPL’s financial advisor. Based on these allegations, plaintiffs seek to have the merger agreement rescinded. Plaintiffs also seek damages and attorneys’ fees.

Defendants date to answer, move to dismiss, or otherwise respond to the lawsuit has been indefinitely extended. Neither Energy XXI nor EPL can predict the outcome of the lawsuit or any others that might be filed subsequent to the date of the filing of this quarterly report; nor can either Energy XXI or EPL predict the amount of time and expense that will be required to resolve the lawsuit. The defendants intend to vigorously defend the lawsuit.

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 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 common stock as reported on the NASDAQ.

   
  Unrestricted
Common Stock
     High   Low
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  
Fiscal 2014
                 
First Quarter     30.02       22.17  
Second Quarter     32.45       25.15  
Third Quarter     25.86       21.22  
Fourth Quarter     24.01       20.29  

As of July 31, 2014, there were approximately 509 holders of record of our 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.

We paid quarterly cash dividends of $0.12 per share to holders of our common stock on September 13, 2013, December 13, 2013, March 14, 2014 and June 13, 2014 to shareholders of record on August 30, 2013, November 29, 2013 and February 28, 2014 and May 30, 2014, respectively.

On July 16, 2014, 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 12, 2014 to shareholders of record on August 29, 2014.

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

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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.

In November 2013, concurrently with the offering of our 3.0% Senior Convertible Notes due 2018, our Board of Directors approved an additional one time repurchase of our common stock of approximately $76 million, pursuant to which one of the Company’s wholly-owned subsidiaries repurchased 2,776,200 shares of the Company’s common stock for approximately $76 million, at a weighted average price per share, excluding fees, of $27.39.

We have not made any repurchases under our repurchase program during the quarter ended June 30, 2014 and we have suspended the repurchase program indefinitely to reduce our capital needs.

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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,
     2014   2013   2012   2011   2010
     (In Thousands, Except per Share Amounts)
Income Statement Data
                                            
Revenues   $ 1,230,725     $ 1,208,845     $ 1,303,403     $ 859,370     $ 498,931  
Depreciation, Depletion and Amortization (“DD&A”)     423,319       376,224       367,463       293,479       181,640  
Operating Income     280,411       361,805       483,284       208,923       102,047  
Other Income (Expense) – Net     (164,211 )      (113,091 )      (108,811 )      (132,006 )      (58,483 ) 
Net Income     59,111       162,081       335,827       64,655       27,320  
Basic Earnings per Common Share   $ 0.64     $ 1.90     $ 4.10     $ 0.42     $ 0.56  
Diluted Earnings per Common Share   $ 0.64     $ 1.86     $ 3.85     $ 0.42     $ 0.56  
Cash Flow Data
                                            
Provided by (Used in)
                                            
Operating Activities   $ 545,460     $ 638,148     $ 785,514     $ 387,725     $ 121,213  
Investing Activities
                                            
Acquisitions     (849,641 )      (161,164 )      (6,401 )      (1,012,262 )      (293,037 ) 
Investment in properties     (788,676 )      (816,105 )      (570,670 )      (281,233 )      (145,112 ) 
Other     93,742       (16,734 )      7,478       38,423       53,989  
Total Investing Activities     (1,544,575 )      (994,003 )      (569,593 )      (1,255,072 )      (384,160 ) 
Financing Activities     1,144,921       238,768       (127,241 )      881,530       188,246  
Increase (Decrease) in Cash   $ 145,806     $ (117,087 )    $ 88,680     $ 14,183     $ (74,701 ) 
Dividends Paid per Average Common Share   $ 0.48     $ 0.33     $ 0.07              

         
  June 30,
     2014   2013   2012   2011   2010
     (In Thousands)
Balance Sheet Data
                                            
Total Assets   $ 7,436,778     $ 3,611,711     $ 3,130,947     $ 2,798,860     $ 1,566,491  
Long-term Debt Including Current Maturities     3,759,644       1,370,045       1,018,344       1,113,387       774,600  
Stockholders’ Equity     1,797,830       1,437,246       1,405,840       946,697       436,561  
Common Shares Outstanding     93,720       76,486       78,838       76,203       50,637  

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  Year Ended June 30,
Operating Highlights   2014   2013   2012   2011   2010
     (In Thousands, Except per Unit Amounts)
Operating revenues
                                            
Crude oil sales   $ 1,104,206     $ 1,067,686     $ 1,186,193     $ 777,869     $ 383,928  
Natural gas sales     135,792       112,753       88,608       101,815       69,399  
Hedge gain (loss)     (9,273 )      28,406       28,602       (20,314 )      45,604  
Total revenues     1,230,725       1,208,845       1,303,403       859,370       498,931  
Percent of operating revenues from
crude oil
                                            
Prior to hedge gain (loss)     89 %      90 %      93 %      88 %      85 % 
Including hedge gain (loss)     89 %      89 %      91 %      84 %      78 % 
Operating expenses
                                            
Lease operating expense
                                            
Insurance expense     31,183       32,737       28,521       27,876       27,603  
Workover and maintenance     66,481       65,118       56,413       33,095       19,630  
Direct lease operating expense     268,083       239,308       225,881       178,507       95,379  
Total lease operating expense     365,747       337,163       310,815       239,478       142,612  
Production taxes     5,427       5,246       7,261       3,336       4,217  
Gathering and transportation     23,532       24,168       16,371       12,499        
Depreciation, depletion and amortization     423,319       376,224       367,463       293,479       181,640  
General and administrative     96,402       71,598       86,276       75,091       49,667  
Other – net     35,887       32,641       31,933       26,564       18,748  
Total operating expenses     950,314       847,040       820,119       650,447       396,884  
Operating income   $ 280,411     $ 361,805     $ 483,284     $ 208,923     $ 102,047  
Sales volumes per day
                                            
Natural gas (MMcf)     89.7       88.6       81.5       67.2       42.6  
Crude oil (MBbls)     30.1       28.3       30.5       23.4       14.7  
Total (MBOE)     45.0       43.1       44.1       34.6       21.8  
Percent of sales volumes from crude oil     67 %      66 %      69 %      68 %      67 % 
Average sales price
                                            
Natural gas per Mcf   $ 4.15     $ 3.48     $ 2.97     $ 4.15     $ 4.47  
Hedge gain per Mcf     0.11       0.47       0.94       1.54       2.68  
Total natural gas per Mcf   $ 4.26     $ 3.95     $ 3.91     $ 5.69     $ 7.15  
Crude oil per Bbl   $ 100.59     $ 103.48     $ 106.17     $ 90.95     $ 71.73  
Hedge gain (loss) per Bbl     (1.18 )      1.29       0.04       (6.80 )      0.75  
Total crude oil per Bbl   $ 99.41     $ 104.77     $ 106.21     $ 84.15     $ 72.48  
Total hedge gain (loss) per BOE   $ (0.56 )    $ 1.81     $ 1.77     $ (1.61 )    $ 5.74  
Operating revenues per BOE   $ 74.88     $ 76.95     $ 80.74     $ 67.98     $ 62.83  
Operating expenses per BOE
                                            
Lease operating expense
                                            
Insurance expense     1.90       2.08       1.77       2.21       3.48  
Workover and maintenance     4.04       4.15       3.49       2.62       2.47  
Direct lease operating expense     16.31       15.23       13.99       14.12       12.01  
Total lease operating expense per BOE     22.25       21.46       19.25       18.95       17.96  
Production taxes     0.33       0.33       0.45       0.26       0.53  
Gathering and transportation     1.43       1.54       1.01       0.98        
Depreciation, depletion and amortization     25.75       23.95       22.76       23.22       22.87  
General and administrative     5.87       4.56       5.34       5.94       6.25  
Other – net     2.19       2.08       1.98       2.10       2.36  
Total operating expenses per BOE     57.82       53.92       50.79       51.45       49.97  
Operating income per BOE   $ 17.06     $ 23.03     $ 29.95     $ 16.53     $ 12.86  

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  Quarter Ended
Operating Highlights   June 30,
2014
  Mar. 31,
2014
  Dec. 31,
2013
  Sept. 30,
2013
  June 30,
2013
     (In Thousands, Except per Unit Amounts)
Operating revenues
                                            
Crude oil sales   $ 294,974     $ 254,641     $ 263,626     $ 290,965     $ 270,623  
Natural gas sales     34,508       37,562       31,138       32,584       38,630  
Hedge gain (loss)     (5,348 )      (7,020 )      2,052       1,043       5,072  
Total revenues     324,134       285,183       296,816       324,592       314,325  
Percent of operating revenues from
crude oil
                                            
Prior to hedge gain (loss)     90 %      87 %      89 %      90 %      88 % 
Including hedge gain (loss)     89 %      88 %      88 %      89 %      87 % 
Operating expenses
                                            
Lease operating expense
                                            
Insurance expense     8,357       6,410       7,920       8,496       7,462  
Workover and maintenance     14,408       17,797       19,690       14,586       15,622  
Direct lease operating expense     79,806       59,417       66,179       62,681       59,371  
Total lease operating expense     102,571       83,624       93,789       85,763       82,455  
Production taxes     1,750       1,090       1,189       1,398       1,481  
Gathering and transportation     6,509       5,700       5,978       5,345       5,668  
DD&A     119,691       99,899       103,513       100,216       96,846  
General and administrative     30,824       24,208       17,698       23,672       12,299  
Other – net     8,112       5,861       13,147       8,767       3,829  
Total operating expenses     269,457       220,382       235,314       225,161       202,578  
Operating income   $ 54,677     $ 64,801     $ 61,502     $ 99,431     $ 111,747  
Sales volumes per day
                                            
Natural gas (MMcf)     84.8       83.7       89.3       100.8       107.4  
Crude oil (MBbls)     32.0       28.4       30.2       29.7       28.9  
Total (MBOE)     46.1       42.3       45.1       46.6       46.8  
Percent of sales volumes from crude oil     69 %      67 %      67 %      64 %      62 % 
Average sales price
                                            
Natural gas per Mcf   $ 4.47     $ 4.98     $ 3.79     $ 3.51     $ 3.95  
Hedge gain (loss) per Mcf     (0.02 )      (0.31 )      0.42       0.30       0.23  
Total natural gas per Mcf   $ 4.45     $ 4.67     $ 4.21     $ 3.81     $ 4.18  
Crude oil per Bbl   $ 101.45     $ 99.71     $ 94.85     $ 106.31     $ 102.82  
Hedge gain (loss) per Bbl     (1.78 )      (1.83 )      (0.50 )      (0.63 )      1.08  
Total crude oil per Bbl   $ 99.67     $ 97.88     $ 94.35     $ 105.68     $ 103.90  
Total hedge gain (loss) per BOE   $ (1.28 )    $ (1.84 )    $ 0.49     $ 0.24     $ 1.19  
Operating revenues per BOE   $ 77.28     $ 74.85     $ 71.54     $ 75.78     $ 73.78  
Operating expenses per BOE
                                            
Lease operating expense
                                            
Insurance expense     1.99       1.68       1.91       1.98       1.75  
Workover and maintenance     3.44       4.67       4.75       3.41       3.67  
Direct lease operating expense     19.03       15.59       15.95       14.63       13.94  
Total lease operating expense per BOE     24.46       21.94       22.61       20.02       19.36  
Production taxes     0.42       0.29       0.29       0.33       0.35  
Gathering and transportation     1.55       1.50       1.44       1.25       1.33  
DD&A     28.54       26.22       24.95       23.40       22.73  
General and administrative     7.35       6.35       4.27       5.53       2.89  
Other – net     1.93       1.54       3.17       2.05       0.90  
Total operating expenses per BOE     64.25       57.84       56.73       52.58       47.56  
Operating income per BOE   $ 13.03     $ 17.01     $ 14.81     $ 23.20     $ 26.22  

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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 Part I, Item 1A “Risk Factors” in this Form 10-K.

Overview

Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries (“Energy XXI”, “us”, “we”, “our”, or “the Company”) is an independent oil and natural gas exploration and production company. 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 our 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”).

With our principal operating subsidiary 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 in the Gulf of Mexico Shelf (“GoM Shelf”). Energy XXI is the largest publicly traded independent operator on the GoM Shelf operating seven of the largest GoM Shelf fields.

Our acquisitions since our inception in 2005 have been primarily oil-focused at an average acquisition price of approximately $21.35 per barrel of oil equivalent (“BOE”) and have provided us access to 767,445 net acres, ownership in 258 blocks, existing infrastructure to facilitate our growth and 16,036 square miles of 3D seismic data.

The acquisition of EPL Oil & Gas, Inc. (“EPL”) on June 3, 2014 (the “EPL Acquisition”) significantly increased our scope of operation. The EPL assets are located on the GoM Shelf, which we expect to integrate well with our existing portfolio on the GoM Shelf and provide significant near term cost savings.

We intend to grow and strengthen our position as the largest publicly traded independent operator on the GoM Shelf, operating seven of the largest GoM Shelf fields, in a safe environment, with a focus on delivering value for our shareholders. We offer scalability and potential for high rates of return by developing and exploring high quality oil-producing assets with low decline rates.

We pursue growth opportunities through exploration and development drilling on our existing core properties to enhance production and ultimate recovery of reserves, supplemented by strategic acquisitions from time to time. Our acquisition strategy is to target mature, oil-producing properties on the GoM Shelf and the U.S. Gulf Coast that have not been thoroughly exploited by prior operators. We believe these activities will provide us with an inventory of low-risk recompletion and extension opportunities in our geographic area of expertise.

We exploit our acquired properties through production optimization, technology application, infill drilling, and extensive field studies of the primary reservoirs to maximize production and identify oil weighed opportunities that enable us to maintain a large inventory of exploitation opportunities while continuing to drill in these prolific large oil reservoirs.

We utilize a portion of our exploration budget for two play concepts on the GoM Shelf; namely the counter regional salt play and the ultra-deep play, where we expect significant exploration upside.

At June 30, 2014, our total proved reserves were 246.2 MMBOE of which 75% were oil and 61% were classified as proved developed. We operated or had an interest in 984 gross producing wells on 432,954 net developed acres, including interests in 61 producing fields. We believe operating our assets is a key to our success and approximately 96% of our proved reserves are on properties operated by us. Our geographical concentration on the GoM Shelf enables us to manage the operated fields efficiently and our high number of wellbore locations provides diversification of our production and reserves.

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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. Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges and expect to carry those hedges through the end of contract term beginning from June 2014 through December 2015. 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.

Acquisition and Dispositions

Fiscal Year 2014

Black Elk Interest

On December 20, 2013, we closed on the acquisition of certain offshore Louisiana interests in West Delta 30 field from Black Elk Energy Offshore Operations, LLC for a total cash consideration of $10.4 million. This acquisition was effective October 1, 2013 and we are the operator of these properties.

Walter Oil & Gas Corporation Oil and Gas Properties interests Acquisition

On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block from Walter Oil & Gas Corporation for a total cash consideration of approximately $22.8 million. This acquisition was effective January 1, 2014 and we are the operator of these properties.

Acquisition of EPL

On June 3, 2014, we completed the EPL Acquisition, pursuant to which we acquired all of EPL’s outstanding shares for total consideration of approximately $2.5 billion, including the assumption of EPL’s debt. The consideration to be received by EPL stockholders was valued at $39.00 per EPL share based on Energy XXI’s closing price of $23.37 per share as of March 11, 2014. The aggregate consideration to EPL shareholders was paid 65% in cash and 35% in Energy XXI common shares and consisted of approximately $1.01 billion in cash and approximately 23.3 million common shares of Energy XXI. Upon closing, Energy XXI shareholders owned approximately 75% of the combined company and EPL shareholders owned the remaining 25%.

Sale of Oil and Gas properties interests in Eugene Island 330 and South Marsh Island 128 fields

On April 1, 2014, we closed on the sale of our interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of our equity method investee, Energy XXI M21K, LLC, for cash consideration of approximately $122.9 million. Revenues and expenses related to these two fields have been included in our results of operations through March 31, 2014. The proceeds were recorded as a reduction to our oil and gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $124.4 million, which was subject to customary closing adjustments.

Sale of Oil and Gas properties interests in South Pass 49 field

On June 3, 2014, Energy XXI GOM, LLC (“EXXI GOM”), our wholly owned indirect subsidiary closed on the sale of its interests in South Pass 49 field to EPL, which is our wholly owned indirect subsidiary, for cash consideration of approximately $230 million. As this sale is between our two wholly owned indirect subsidiaries, there is no impact on a consolidated basis to our revenues and expenses or the full cost pool related to this transaction.

Fiscal Year 2013

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 (“ExxonMobil”) 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

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into a joint venture agreement with ExxonMobil 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. The objective targets at the Pendragon well, the initial prospect, were not reached as it encountered mechanical issues and was plugged and abandoned. Subsequently, we began drilling the Merlin well located at Vermilion Block 179; the Merlin well did not encounter any commercial hydrocarbons and was plugged and abandoned. We are currently negotiating our joint venture with ExxonMobil with plans to include analyzing the Pendragon and Merlin wells’ data along with reprocessing the 3D seismic information to determine the future drilling activities on the Vermilion Block.

Dynamic Offshore oil and gas properties interests acquisition

On November 7, 2012, we acquired 100% of the interests in VR 164 held by Dynamic Offshore Resources, LLC for approximately $7.2 million.

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 from McMoRan Oil and Gas, LLC for a total cash consideration of $79.3 million. This acquisition was effective January 1, 2013 and we are the operator of these properties.

RoDa oil and gas properties interests acquisition

On March 14, 2013, we acquired 100% of the interests in the Bayou Carlin field held by RoDa Drilling LP for $32.7 million. This acquisition was 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 from Tammany Energy Ventures, LLC for a total cash consideration of $8.3 million. This acquisition was effective June 1, 2013 and we are the operator of these properties.

Apache Joint Venture

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

The area of mutual interest under this Exploration 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 $33.7 million was incurred through June 30, 2014. Drilling on the first well commenced in May 2013 on the southern flank of the salt dome, penetrating eight oil sands and one gas bearing sand. In February 2014, we commenced drilling an offset well which also encountered multiple hydrocarbon bearing sands. Presently both the wellbores have been suspended for future utility and we expect to complete 3D WAZ seismic data analysis in January 2015. As of June 30, 2014, our share of costs related to these wells was approximately $28.1 million.

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 and Salt Play Activity

Our partnership with the operator Freeport McMoRan Oil and Gas, LLC (formerly McMoRan Exploration Company and now acquired by Freeport-McMoRan, Inc.) retains a leading acreage position in the emerging Inboard Lower Tertiary and Cretaceous gas trend, located in the GoM Shelf and onshore South Louisiana. We have participated in eight projects to date, both offshore and onshore, with our participations ranging from approximately 9% to 20%. This emerging exploration trend focuses on the subsalt Lower Wilcox and Cretaceous sections. The Lomond North well is in the process of being completed and the Davy Jones No. 2 well was determined to be non-commercial in the Tuscaloosa sand and awaiting text of Wilcox sands.

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In our joint venture with Fieldwood and Apache in the Main Pass area, we have drilled two wells on the Main Pass 295 structure. The #1 BP1 well was drilled to a depth of 19,555 feet MD/19,510 feet TVD on the southern flank of the salt dome, penetrating eight oil sands and one gas-bearing sand. An offset well, the Main Pass 295 #3, was drilled to a depth of 10,561 feet MD/10,332 feet TVD and also has encountered multiple hydrocarbon-bearing sands. Both wellbores have been suspended for future use. This joint venture is expecting 3D WAZ seismic data analysis to be completed in January 2015.

We are currently negotiating an extension of our joint venture with ExxonMobil in the Vermilion area with a plan to reprocess 3D seismic data during 2014 to help determine future drilling activity.

Outlook

We are subject to oil and natural gas production declines in our producing properties. We attempt to replace this declining production through our drilling and recompletion program and acquisitions. While we 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. Further, 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.

We completed the EPL Acquisition on June 3, 2014, pursuant to which we acquired all of EPL’s outstanding shares for total consideration of approximately $2.5 billion, including the assumption of EPL’s debt.

The combined company now has a significantly increased enterprise value and we expect this increased scale will provide us with the following opportunities:

to increase equity market liquidity, lower insurance and weather based insurance linked securities costs and provide more institutional sponsorship;
the technical teams of both companies have complementary strengths and expertise that should make the combined company a stronger competitor in the Gulf of Mexico;
to utilize certain of EPL’s existing infrastructure to more efficiently and timely drill identified prospects;
the combined company will have a significantly broader asset portfolio, which we expect will allow it to better allocate development and exploration dollars to focus on the best opportunities;
to achieve operating efficiencies and lower costs through optimization of helicopters, vessels and the consolidation of shore bases; and,
to lower general and administrative expenses through consolidation of corporate support functions.

In addition to utilizing cash on hand to finance the EPL Acquisition, on May 12, 2014, we sold $650 million in aggregate principal amount of the Company’s 6.875% senior unsecured notes due 2024 (the “6.875% Senior Notes”) and concurrent with closing of the EPL Acquisition on June 3, 2014, we increased our borrowing base under our revolving credit facility to $1.5 billion to enhance liquidity.

To enable us to focus on the successful integration of the EPL operations and to reduce our capital needs, we:

canceled our plans to expand overseas in Malaysia and terminated our joint venture with Ping Petroleum Limited to pursue opportunities in that region;
suspended the stock repurchase program; and
sold certain non-operated interests in the Eugene Island 330 and South Marsh Island 128 fields.

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The acquisition of EPL had a material effect on the Company’s liquidity and planned future capital expenditures as we have incurred significant debt in connection with the closing of the EPL Acquisition. As a result of the acquisition, our net debt to total capitalization increased from 55% to approximately 67%. Our focus during the next few years will be to maximize cash flow to reduce leverage with the general view of having a long-term debt to total capitalization ratio of below 60%. We anticipate that we will be cash flow positive as a combined company which will enable us to pay down debt we have incurred to complete the EPL Acquisition; however, the timing and level of cash flows will depend in part on the speed at which we are able to integrate operations to realize consolidation benefits and will be further affected by one time charges incurred during the integration process. In the near-term we will focus on maximizing returns on existing assets by deploying capital resources on lower risk development drilling in the fields where we have previously enjoyed success, reducing capital commitments on exploration and other activities that do not provide incremental production while we seek to improve cash flow and pay down debt. To further accelerate the reduction in leverage, we may pursue arrangements with third parties to enable us to further reduce the amount of required capital commitments. However, there can be no assurance any of these discussions will prove successful.

On March 19, 2014, we were the high bidder in twenty nine shallow-water blocks in the Central Gulf of Mexico Lease Sale 231, with a total investment of approximately $10.8 million. Ten blocks were bid solely by us and included acreage in Ship Shoal, South Pass, West Delta, Grand Isle, Eugene Island, Main Pass and South Timbalier. Two blocks were jointly bid with Fieldwood and Apache in Viosca Knoll and Main Pass. Our bids were focused on areas adjacent to existing operations, which could provide near-term development opportunities. These bids were accepted by the BOEM in May and June 2014.

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. Total capital expenditures for fiscal 2015, excluding any potential acquisitions, are estimated at $875 million. Approximately 54% will be focused on development of our core properties and the remainder on facilities, exploration, capitalized overhead, land and abandonment costs.

Consistent with our business strategy, we intend to invest the capital necessary to maintain our production at existing levels over the long-term provided that it is economical to do so, based on the commodity price environment. Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. We 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. 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.

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

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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.

Results of Operations

Year Ended June 30, 2014 Compared With the Year Ended June 30, 2013

Our consolidated net income available for common stockholders was $47.6 million or $0.64 diluted income per common share (“per share”) in fiscal 2014 as compared to consolidated net income available for common stockholders of $150.6 million or $1.86 diluted income per share in fiscal 2013. This decrease was primarily due to 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)
     2014   2013   Amount   Percent
             (In Thousands)
Price Variance(1)
                                            
Crude oil sales prices (per Bbl)   $ 99.41     $ 104.77     $ (5.36 )      (5 )%    $ (58,842 ) 
Natural gas sales prices (per Mcf)   $ 4.26     $ 3.95     $ 0.31       8 %      10,059  
Total price variance                             (48,783 ) 
Volume Variance
                                            
Crude oil sales volumes (MBbls)     10,978       10,318       660       6 %      69,083  
Natural gas sales volumes (MMcf)     32,754       32,354       400       1 %      1,580  
BOE sales volumes (MBOE)     16,437       15,710       727       5 %          
Percent of BOE from crude oil     67 %      66 %                      
Total volume variance                             70,663  
Total price and volume variance                           $ 21,880  

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

Revenue Variances

       
  Year Ended June 30,   Increase
     2014   2013   Amount   Percent
       (In Thousands)    
Crude oil   $ 1,091,223     $ 1,080,982     $ 10,241       1 % 
Natural gas     139,502       127,863       11,639       9 % 
Total revenues   $ 1,230,725     $ 1,208,845     $ 21,880       2 % 

Oil and Natural Gas Revenues

Our consolidated revenues increased $21.9 million in fiscal 2014. Higher revenues were primarily due to higher crude oil sales volumes and higher natural gas sales prices partially offset by the impact of lower crude oil sales prices. Revenue variances related to commodity prices and sales volumes are described below.

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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 $48.8 million in fiscal 2014. Average crude oil prices, including a $1.18 realized loss per barrel related to hedging activities, decreased $5.36 per barrel in fiscal 2014, resulting in decreased revenues of $58.8 million. Average natural gas prices, including a $0.11 realized gain per Mcf related to hedging activities, increased $0.31 per Mcf during fiscal 2014, resulting in increased revenues of $10.0 million. Commodity prices are affected by many factors that are outside of our control.

Sales Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Higher BOE sales volumes in fiscal 2014 resulted in increased revenues of $70.7 million. Crude oil sales volumes increased 660 MBbls in fiscal 2014, resulting in higher revenues of $69.1 million. The increase in crude oil sales volumes in fiscal 2014 was primarily due to the results of our capital program and the EPL Acquisition partially offset by the shut-in of production and natural decline. Natural gas sales volumes increased 400 MMcf in fiscal 2014, resulting in improved revenues of $1.6 million. The increase in natural gas sales volumes in fiscal 2014 was primarily due to the results of our capital program and the EPL Acquisition partially offset by the shut-in of production 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
     2014   2013
     Amount   Per BOE   Amount   Per BOE
     (In Thousands, except per unit amounts)
Costs and expenses
                                            
Lease operating expense
                                            
Insurance expense   $ 31,183     $ 1.90     $ 32,737     $ 2.08     $ (1,554 ) 
Workover and maintenance     66,481       4.04       65,118       4.15       1,363  
Direct lease operating expense     268,083       16.31       239,308       15.23       28,775  
Total lease operating expense     365,747       22.25       337,163       21.46       28,584  
Production taxes     5,427       0.33       5,246       0.33       181  
Gathering and transportation     23,532       1.43       24,168       1.54       (636 ) 
DD&A     423,319       25.75       376,224       23.95       47,095  
Accretion of asset retirement obligation     30,183       1.84       30,885       1.97       (702 ) 
General and administrative expense     96,402       5.87       71,598       4.56       24,804  
Loss on derivative financial instruments     5,704       0.35       1,756       0.11       3,948  
Total costs and expenses   $ 950,314     $ 57.82     $ 847,040     $ 53.92     $ 103,274  
Other (income) expense
                                            
Loss from equity method investees   $ 4,781     $ 0.29     $ 6,397     $ 0.41     $ (1,616 ) 
Other (income) expense – other     (3,298 )      (0.20 )      (1,965 )      (0.13 )      (1,333 ) 
Interest expense     162,728       9.90       108,659       6.92       54,069  
Total other (income) expense   $ 164,211     $ 9.99     $ 113,091     $ 7.20     $ 51,120  

Costs and expenses increased $103.3 million in fiscal 2014. This increase in costs and expenses was due in part to higher production related expenses, higher DD&A expense and higher general and administrative expense in fiscal 2014. Below is a discussion of costs and expenses.

Lease operating expense increased $28.6 million in fiscal 2014 compared to fiscal 2013. 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.

DD&A expense increased $47.1 million due to a higher DD&A rate ($29.6 million) and higher equivalent production ($17.5) million.

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General and administrative expense increased $24.8 million in fiscal 2014 principally as a result of one-time costs of approximately $13.6 million associated with the EPL Acquisition and higher employee related costs of approximately $11.2 million due an increase in the number of employees in 2014.

Other (income) expense increased $51.1 million in fiscal 2014 as compared to fiscal 2013 principally due to higher interest expense due to increased borrowings.

Income Tax Expense

Income tax expense decreased $29.5 million in fiscal 2014 compared to fiscal 2013. The effective income tax rate for fiscal 2014 increased from fiscal 2013 from 34.8% to 49.1%. The increase in the effective tax rate from fiscal year 2013 of 34.8% to 49.1% in 2014 was due to the tax effect of the release of a $7.8 million valuation allowance in 2013 (which did not occur in 2014), and to the disallowance (for tax purposes) of certain transaction costs related to the EPL acquisition, among other customary permanent differences. The effect of the increase in the effective income tax rate in fiscal 2014 was partially offset by lower pre-tax income in fiscal 2014.

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 income 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 to 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 )% 

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Oil and Natural Gas Revenues

Our consolidated revenues decreased $94.6 million in fiscal 2013. Lower revenues were primarily due to lower crude oil 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.

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.

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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.

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.

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 by 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, 2014
  Year Ended
June 30, 2013
     Oil
MMBbls
  Natural Gas Bcf   MMBOE   Oil
MMBbls
  Natural Gas Bcf   MMBOE
Proved
                                                     
Developed     112.8       222.9       149.9       80.2       175.6       109.5  
Undeveloped     72.6       142.0       96.3       53.4       93.5       69.0  
Total Proved     185.4       364.9       246.2       133.6       269.1       178.5  
                                                                                                                                

Our proved developed reserve estimates increased by 40.4 MMBOE or 37% to 149.9 MMBOE at June 30, 2014 from 109.5 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 52.3 MMBOE, primarily in the EPL Acquisition.
Additions of 5.4 MMBOE from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from the 4 fields West Delta 30, Main Pass 61, Main Pass 73 and Grand Isle 16.

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Offset by:

Downward revision of 2.7 MMBOE, mainly due to lower than forecasted per well throughput at West Delta 073 and sanding issues at South Timbalier 54, offset by positive performance revision at West Delta 030 and South Pass 049
Divestiture of 4.7 MMBOE, and
Production of 16.4 MMBOE

Our proved undeveloped reserve estimates increased by 27.3 MMBOE or 40% to 96.3 MMBOE at June 30, 2014 from 69.0 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 24.6 MMBOE, primarily in the EPL Acquisition.
Additions of 15.1 MMBOE, primarily additional drilling locations to make up for the lower throughput per well in West Delta 73, replacement locations for South Timbalier 54 and from identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 61.

Offset by

Downward revision of 5.9 MMBOE, primarily due to lease expiration in South Fresh Water Bayou, reallocation of reserves due to new information from the drilling program in Main Pass 61, and change of fluid type due to new information from the drilling program in West Delta 30.
Conversion of 6.6 MMBOE from proved undeveloped to proved developed reserves.

In the fiscal year ended June 30, 2014, we developed approximately 9.5% of our PUD reserves included in our June 30, 2013 reserve report, consisting of 18 gross, 18 net wells at a net cost of approximately $160.9 million. In addition, we also spent $101.7 million in developing PUD reserves that were still in progress at the end of the fiscal year ended June 30, 2014.

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 newly acquired proved undeveloped reserves. As scheduled in our long range plan, all of our proved undeveloped locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our report, with the exception of two. They are locations to be sidetracked from existing wellbores which are still producing economically thus cannot be drilled until the proved developed producing zones deplete.

Liquidity and Capital Resources

Overview

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. However, future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices and significant backwardation of commodity prices would negatively impact revenues, earnings and cash flows and potentially our liquidity if we do not rein in our spending accordingly. Cash investments are required to fund activities necessary to offset the natural production declines in proved reserves. Our ability to maintain and grow reserves is dependent on the success of our exploration and development activity and our ability to acquire additional reserves at reasonable rates. 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;

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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;
payments of dividends on our common and preferred shares outstanding; and
indirect costs related to our exploration activities, including payroll and other expense attributable to our exploration professional staff.

We borrowed $138 million during fiscal 2014 under our First Lien Credit Agreement, as amended 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 fiscal 2014, we had $789 million in capital expenditures excluding acquisitions, of which $632 million was spent on development of our core properties, $153 million on exploration and $4 million on other assets.

The EPL Acquisition significantly increased our enterprise value and supplemented our existing oil and gas properties portfolio by adding approximately 21,000 BOE/Day in production and 75 MMBOE in reserves and also increased our indebtedness and debt to total capitalization percentage.

At June 30, 2014, we had $145.8 million in cash and cash equivalents invested in money market funds and short term deposits with major financial institutions.

We completed the following financing transactions during fiscal 2014 to finance the EPL Acquisition and supplement our liquidity position:

On September 26, 2013, Energy XXI Gulf Coast, Inc. (“EGC”), our wholly-owned indirect subsidiary, issued $500 million face value of 7.50%, unsecured senior notes due December 15, 2021 at par (“7.50% Senior Notes”). EGC incurred underwriting and direct offering costs of $8.6 million which have been capitalized and will be amortized over the life of the 7.50% Senior Notes. In April 2014, we filed Amendment No. 1 to the registration statement for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes with the SEC. The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014. On or after December 15, 2016, EGC will have the right to redeem all or some of the 7.50% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, EGC may redeem up to 35% of the aggregate principal amount of the 7.50% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, EGC may redeem all or part of the 7.50% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 7.50% Senior Notes upon a change of control and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 7.50% Senior Notes.

On September 27, 2013, EGC entered into the Sixth Amendment (the “Sixth Amendment”) to the Second Amendment and Restated First Lien Credit Agreement (the “First Lien Credit Agreement”). Under the Sixth Amendment, the borrowing base for EGC was increased from $850 million to $1,087.5 million. Additionally, the Sixth Amendment provided EGC the ability to specify interest periods for LIBOR loans of less than a month in length and made some related adjustments to the definition of LIBOR and other technical corrections.

On November 18, 2013, the Company sold $400 million face value of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). The Company incurred underwriting and direct offering costs of $9.5 million, of which $8.1 million have been capitalized and will be amortized over the life of the 3.0% Senior Convertible Notes The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the Company’s election, based on an initial conversion rate of 24.7523 shares of common stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common

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stock). The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.

On April 7, 2014, EGC entered into the Seventh Amendment (the “Seventh Amendment”) to the First Lien Credit Agreement. Under the Seventh Amendment, the borrowing base for EGC was increased from $1,087.5 million to $1,200 million. Additionally, the Seventh Amendment incorporated the 7.50% Senior Notes due 2021 as senior unsecured debt generally permitted under the terms of the First Lien Credit Agreement, so that provisions under the First Lien Credit Agreement for such notes are commensurate with the provisions already existing for EGC’s 9.25% senior unsecured notes due 2017 and 7.75% senior unsecured notes due 2019. Also, the Seventh Amendment allowed for the incurrence of an additional $1,000 million of unsecured debt, subject to certain conditions, including that the minimum liquidity requirements outlined in the First Lien Credit Agreement would be increased in the amount of 25% of any such new debt incurred until such time as the lenders under the First Lien Credit Agreement otherwise provide or waive such increase.

On May 27, 2014, EGC issued $650 million face value of 6.875%, unsecured senior notes due March 15, 2024 at par (“6.875% Senior Notes”). EGC incurred underwriting and direct offering costs of approximately $11 million which have been capitalized and will be amortized over the life of the 6.875% Senior Notes. On or after March 15, 2019, EGC will have the right to redeem all or some of the 6.875% Senior Notes at specified redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption shall be made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 6.875% Senior Notes.

On June 3, 2014, EGC entered into the Eighth Amendment (“the Eighth Amendment”) to the First Lien Credit Agreement. Pursuant to the Eighth Amendment, the borrowing base for EGC was established at $1.5 billion (an increase from $1.2 billion as determined on April 7, 2014) until the next redetermination of such borrowing base pursuant to the terms of the First Lien Credit Agreement. Of this borrowing base amount, EGC established a sub-facility pursuant to the Eighth Amendment for its wholly owned subsidiary, EPL, with a borrowing base of $475 million for such sub-facility. Upon the effectiveness of the Eighth Amendment, EPL immediately borrowed the entire $475 million to refinance the outstanding indebtedness it had under the terms of a credit agreement in existence at the effective time of the acquisition of EPL by EGC. The borrowing base for this sub-facility is subject to redetermination from time to time generally on the same basis as is the overall borrowing base under the First Lien Credit Agreement. Under the Eighth Amendment, EGC and its subsidiaries, other than EPL and its subsidiaries, have guaranteed and secured the indebtedness of EPL and its subsidiaries, but EPL and its subsidiaries have not commensurately guaranteed the obligations of EGC and its other subsidiaries. However, per the terms of the First Lien Credit Agreement, immediately upon EPL’s retirement of its obligations in respect of its outstanding 8.25% Senior Notes due 2018, EPL and its subsidiaries are required to guarantee and secure the obligations generally of EGC and its subsidiaries and such EPL sub-facility shall terminate and the entire borrowing base amount shall thereupon be available to EGC for credit extensions under the terms of the First Lien Credit Agreement. Most of the terms of the Eighth Amendment generally are in regards to incorporating the concept of EPL as a separate “borrower” for purposes of the First Lien Credit Agreement. Interest accrues and is payable on the EPL sub-facility on the same basis as principal amounts outstanding generally under the First Lien Credit Agreement.

Under the Eighth Amendment, the maturity date of the First Lien Credit Agreement is accelerated to August 15, 2017, if EPL’s 8.25% Senior Notes due 2018 are not prepaid, redeemed or refinanced on or prior to such date.

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The Eighth Amendment also incorporates a few additional changes, including the incorporation of the concept of EGC’s 6.875% Senior Notes due 2024 and EPL’s 8.25% Senior Notes due 2018 as senior unsecured debt generally permitted under the terms of the First Lien Credit Agreement, so that provisions under the First Lien Credit Agreement for such notes are commensurate with the provisions already existing for EGC’s 9.25% senior unsecured notes due 2017, 7.75% senior unsecured notes due 2019 and 7.50% senior unsecured notes due 2021. With the Eighth Amendment, EGC retains the ability to further incur $1 billion of permitted unsecured indebtedness, still subject to the condition that the minimum liquidity requirements outlined in the First Lien Credit Agreement would be increased in the amount of 25% of any such new debt incurred until such time as the lenders under the First Lien Credit Agreement otherwise provide or waive such increase. Furthermore, the Eighth Amendment removed the prohibition on the prepayment, redemption or other refinance of EGC’s outstanding 9.25% senior unsecured notes due 2017, 7.75% senior unsecured notes due 2019, 7.50% senior unsecured notes due 2021 and the 6.875% Senior Notes due 2024 and any other permitted unsecured indebtedness incurred by EGC, and instead established certain quantitative liquidity conditions to making any such prepayment, redemption or other refinance of such senior unsecured notes or other permitted unsecured indebtedness. Pursuant to the Eighth Amendment, EGC is permitted to use proceeds from the issuance of further permitted unsecured indebtedness to prepay, redeem or refinance such notes and, upon such action, treat such amount so used as a refinancing of the amount so prepaid redeemed, and restore the availability to incur such amount under the permitted unsecured indebtedness basket.

The First Lien Credit Agreement was entered into by our indirect, wholly-owned subsidiary, EGC, in May 2011 and underwent its Eighth Amendment on June 3, 2014 as noted above. This facility, as amended, has lender commitments of $1.7 billion and matures on April 9, 2018, provided that the facility will mature immediately if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Borrowings are limited to a borrowing base based on oil and gas reserve values which are re-determined 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. The First Lien Credit Agreement, as amended, requires the consolidated EGC to maintain certain financial covenants. Specifically, EGC may not permit the following under First Lien Credit Agreement: (a) EGC’s total leverage ratio to be more than 3.5 to 1.0, (b) EGC’s interest coverage ratio to be less than 3.0 to 1.0, and (c) EGC’s current ratio (in each case as defined in our First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, 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, 2014, EGC was in compliance with the covenants described above and the other financial covenants under the First Lien Credit Agreement, with the possible exception of its total leverage ratio. EGC typically completes its audit after the Bermuda parent company completes its audit. Based upon preliminary calculations, EGC determined it may have exceeded the total leverage ratio covenant and therefore EGC sought a temporary increase in the total leverage ratio covenant. EGC’s total leverage ratio covenant included within Section 7.2.4(a) of the First Lien Credit Agreement, requires EGC to maintain a Total Leverage Ratio (as defined therein) of not more than 3.5 to 1.0 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC’s leverage ratio was estimated to be 3.6 to 1.0 for the quarter ended June 30, 2014. EGC received a waiver from the lenders under the First Lien Credit Agreement on August 22, 2014 with respect to this potential violation for the quarters ending June 30, 2014 and September 30, 2014. The waiver is conditioned upon EGC maintaining a Total Leverage Ratio of not more than 4.25 to 1.00 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC was in compliance with the requirements under the waiver for the fiscal quarter ended June 30, 2014 and expects to be in compliance therewith for the fiscal quarter ended September 30, 2014. EGC is currently in discussions with the lenders under the First Lien Credit Agreement to amend certain of the financial covenants in order to ensure that EGC will be in compliance with the covenants for the remainder of the 2015 fiscal year. There is no assurance that EGC will reach agreement with its lenders on these amendments. In the event an amendment cannot be obtained, EGC believes that it will be able to comply with the current covenants under the First Lien Credit Agreement through June 30, 2015 by taking certain actions within EGC’s control.

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As of June 30, 2014, EGC had $689 million in borrowings and $225.7 million in letters of credit issued under our First Lien Credit Agreement.

In addition to the 7.50% Senior Notes, 3.0% Senior Convertible Notes, and 6.875% Senior Notes as noted above, our other high yield facilities consist of the following.

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.

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.

Our indirect, wholly-owned subsidiary, EGC, is the issuer of each of the 9.25% Senior Notes, 7.75% Senior Notes and 7.50% Senior Notes and 6.875% Senior Notes which are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We and our subsidiaries, other than EGC, have no significant independent assets or operations.

We assumed the 8.25% Senior Notes in EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”) .The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee (the “8.25% Senior Notes Trustee”), governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of consents from the requisite holders of the 8.25% Senior Notes in accordance with the terms and conditions of the Consent Solicitation Statement dated April 7, 2014, pursuant to which we had solicited consents (the “Consent Solicitation”) from the holders of the 8.25% Senior Notes to make certain proposed amendments to certain definitions set forth in the Indenture (the “Proposed COC Amendments”), as reflected in the Supplemental Indenture. The Consent Solicitation was made as permitted by the Merger Agreement. On April 18, 2014, we had received valid consents from holders of an aggregate principal amount of $484.1 million of the 8.25% Senior Notes and that those consents had not been revoked prior to the Consent Time. As a result, the requisite holders of the 8.25% Senior Notes had consented to the Proposed COC Amendments, upon the terms and subject to the conditions set forth in the Consent Solicitation Statement. Accordingly, EPL, the guarantors party thereto and the Trustee

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entered into the Supplemental Indenture. Subject to the terms and conditions set forth in the Statement, we paid an aggregate cash payment equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents to the Proposed COC Amendments were validly delivered and unrevoked.

We maintain approximately $7.5 million and $163 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 2015 capital budget, excluding any potential acquisitions, is expected to be approximately $875 million. Approximately 54 percent will be focused on development of our core properties and the remainder on facilities, exploration, capitalized overhead, land and abandonment costs. We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, from cash on hand, cash flows from operations and borrowings under our credit facility. We believe that our available liquidity is sufficient to meet our capital requirements through June 30, 2015. 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 2015 may change as a result of several factors, including, but not limited to, changes in natural gas and oil sales prices, 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.

Credit and equity markets have rebounded significantly in recent years following the credit crisis, with investors again seeking returns in the market. All three of our debt issuances in the fiscal year ended June 30, 2014 were upsized as a result of investor demand. However, 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 believe that our liquidity and capital resources alternatives available to us will be adequate to meet our funding requirements through June 30, 2015. Additionally, our credit facility is comprised of a syndicate of large domestic and international banks, with no single lender providing more than 5% of the overall commitment amount.

Cash Flows

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

     
  Year Ended June 30,
     2014   2013   2012
     (In thousands)
Net cash provided by operating activities   $ 545,460     $ 638,148     $ 785,514  
Net cash used in investing activities     (1,544,575 )      (994,003 )      (569,593 ) 
Net cash provided by (used in) financing activities     1,144,921       238,768       (127,241 ) 
Net increase (decrease) in cash and cash equivalents   $ 145,806     $ (117,087 )    $ 88,680  

Operating Activities

Net cash provided by operating activities during the year ended June 30, 2014 was $545.5 million as compared to $638.1 million provided by operating activities during fiscal 2013. The decrease is due in part to lower net commodity prices and higher production costs partially offset by higher production volumes. Fiscal 2014 also included lower proceeds from sale of derivatives. Changes in operating assets and liabilities increased $49.2 million during fiscal 2014 primarily due to increases in asset retirement obligations and accounts payable and partially offset by decreases in accounts receivable.

Generally, producing natural gas and crude oil reservoirs have declining production rates. Production rates are impacted by numerous factors, including but not limited to, geological, geophysical and engineering matters, production curtailments and restrictions, weather, market demands and our ability to replace depleting reserves. Our inability to adequately replace reserves could result in a decline in production volumes, one of the key drivers of generating net operating cash flows. For the fiscal year ended June 30, 2014, our reserve replacement ratio, which is calculated by dividing acquisitions, discoveries, extensions of existing fields and

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revisions to proved reserves by total production, was 512%. 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 2015.

Investing Activities

Our investments in properties, including acquisitions, were $1,638.3 million, $977.3 million and $577.1 million for the years ended June 30, 2014, 2013 and 2012, respectively. The increase in cash used in investing activities in comparing fiscal 2014 to fiscal 2013 was primarily due to higher acquisition costs in 2014 and higher investments in properties during fiscal 2014. The main driver in the increase in our investment activities was the EPL Acquisition which resulted in a cash outlay (net of cash acquired) of $812.0 million.

Financing Activities

Cash provided by financing activities was $1,144.9 million for the year ended June 30, 2014 as compared to cash provided in financing activities of $238.8 million for the year ended June 30, 2013. During the year ended June 30, 2014, total proceeds from issuance of common stock were $4.0 million. Repurchases of the company’s common stock were $184.3 million under our share repurchase program and net proceeds from our long-term borrowings were $1,341.4 million. During the year ended June 30, 2013, total proceeds from the issuance of common and preferred stock were $7.0 million and net proceeds of our long-term borrowings were $332.7 million.

Contractual Obligations and Other Commitments

The table below provides estimates of the timing of future payments that, as of June 30, 2014, 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)   $ 3,759,644     $ 15,020     $ 8,595     $ 2,586,029     $ 1,150,000  
Interest on long-term debt(1)     1,258,954       239,769       476,755       277,339       265,091  
Operating leases(2)     36,310       4,163       9,729       8,452       13,966  
Performance bonds(2)     170,500       151,300       19,200                    
Drilling rig commitments(2)     61,899       61,899                             
Letters of credit(2)     225,654       315                225,339           
Consulting fees(3)     2,525       2,525                             
Total contractual obligations     5,515,486       474,991       514,279       3,097,159       1,429,057  
Other Obligations
                                            
Asset retirement obligations(4)     559,834       79,649       41,518       38,294       400,373  
Total obligations   $ 6,075,320     $ 554,640     $ 555,797     $ 3,135,453     $ 1,829,430  

(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) Payable to EPL’s former chief executive officer and chief financial officer pursuant to the EPL Acquisition.
(4) 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.

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Off-Balance Sheet Arrangements

We may enter into off-balance sheet transactions which may give rise to material off-balance sheet liabilities. As of June 30, 2014, the material off-balance sheet transactions entered into by us include drilling rig contracts, operating lease agreements and consulting agreements with EPL’s former chief executive officer and chief financial officer. See contractual obligations table above. Other than the off-balance sheet transactions listed above, we have no other transactions, arrangements or relationships with other persons that are reasonably likely to materially affect our liquidity or availability of our requirements for capital resources.

Critical Accounting Policies

We have identified the following policies as critical to the understanding of our financial condition and 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 U.S. GAAP, with no need for management’s judgment in selecting their application. There are also areas in which management’s judgment in selecting any available alternative would not produce a materially different result. However, certain accounting policies are important to the portrayal of our financial condition and results of operations and require management’s most subjective or complex judgments. In applying those policies, management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. Our critical accounting policies and estimates are set forth below. Certain of these accounting policies and estimates are particularly sensitive because of their complexity and the possibility that future events affecting them may differ materially from our management’s current judgment. Our most sensitive estimate affecting our financial statements are 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

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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, 2014, 2013 and 2012, a 10% decrease in oil and gas prices would not impact the results of our full cost ceiling limitation test.

Business Combinations.  For properties acquired in a business combination, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes are recorded for any differences between the assigned values and tax basis of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. Any excess of amounts assigned to assets and liabilities over the purchase price is recorded as a gain on bargain purchase. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of oil and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.

Estimated deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Goodwill.  Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in fiscal 2014 with the EPL Acquisition and has been recorded to our oil and gas reporting unit. Events affecting oil and natural gas prices may cause a decrease in the fair value of the reporting unit, and we could have an impairment of goodwill in future periods.

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 natural gas properties cost that are depleted over

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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 directly 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, 2014 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,

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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 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 adopted ASU 2011-11 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

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 accumulated other comprehensive income 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 adopted ASU 2013-02 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

In July 2013 the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU-2013-11). ASU 2013-11 clarifies that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. We are currently evaluating the provisions of ASU 2013-11 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

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, 2014, 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.

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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.

At June 30, 2014, our natural gas contracts outstanding had a liability position of $1 million. A 10% increase in natural gas prices would increase the liability by approximately $3 million, while a 10% decrease in natural gas prices would reduce the liability by approximately $2.8 million. Also, at June 30, 2014, our crude oil contracts outstanding had a liability position of $30.8 million. A 10% increase in crude oil prices would increase the liability by approximately $63.3 million, while a 10% decrease in crude oil prices would reduce the liability by approximately $57.5 million. These changes assume volatility based on prevailing market parameters at June 30, 2014.

As of June 30, 2014, 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 2014 – December 2014     Three-Way Collars       Oil-Brent-IPE       766              $ 69.00     $ 89.00     $ 124.99  
July 2014 – December 2014     Put Spreads       Oil-Brent-IPE       431                66.43       86.43        

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        Weighted Average Contract Price
           Swaps   Collars/Put Spreads
Period   Type of Contract   Index   Volumes (MBbls)   Fixed Price   Sub Floor   Floor   Ceiling
July 2014 – December 2014     Collars       Oil-Brent-IPE       368                         90.00       108.38  
July 2014 – December 2014     Put Spreads       NYMEX-WTI       1,230                70.00       90.00           
July 2014 – December 2014     Put       NYMEX-WTI       460                         90.00           
July 2014 – December 2014     Roll Swap       NYMEX-WTI       2,295     $ 1.03                             
July 2014 – December 2014     Three-Way Collars       NYMEX-WTI       610                70.00       90.00       137.20  
July 2014 – December 2014     Swaps       ARGUS-LLS       1,614       92.84                             
January 2015 – December 2015     Three-Way Collars       Oil-Brent-IPE       3,650                71.00       91.00       113.75  
January 2015 – December 2015     Swaps       Oil-Brent-IPE       548       97.70                             
January 2015 – December 2015     Collars       ARGUS-LLS       1,825                         80.00       123.38  
January 2015 – December 2015     Put       NYMEX-WTI       1,813                         88.76           
January 2015 – December 2015     Roll Swap       NYMEX-WTI       3,180       1.03                             

As of June 30, 2014, we had the following net open natural gas derivative positions:

             
        Weighted Average Contract Price
           Swaps   Collars/Put Spreads
Period   Type of Contract   Index   Volumes (MMBtu)   Fixed Price   Sub Floor   Floor   Ceiling
July 2014 – December 2014     Three-Way Collars       NYMEX-HH       8,187              $ 3.36     $ 4.00     $ 4.60  
July 2014 – December 2014     Put Spreads       NYMEX-HH       1,013                3.25       4.00           
July 2014 – December 2014     Swaps       NYMEX-HH       920     $ 4.01                             
January 2015 – December 2015     Swaps       NYMEX-HH       1,570       4.31                             

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, 2014, please see Note 9 —  Derivative Financial Instruments to our Consolidated Financial Statements in this Form 10-K.

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 82% percent of the Company’s debt. As of June 30, 2014, total debt included $689 million of floating-rate debt. As a result, our period-end interest costs will fluctuate based on short-term interest rates on approximately 18 percent of our total debt outstanding as of June 30, 2014. A 10 percent change in floating interest rates on period-end floating debt balances would change annual interest expense by approximately $86,000. 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.

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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, 2014. 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). Management has excluded EPL Oil & Gas, Inc. (“EPL”) from its assessment of internal control over financial reporting as of June 30, 2014 as it was acquired by the Company in a business combination on June 3, 2014. EPL is our wholly-owned indirect subsidiary whose total assets and total revenues represent 47% and 5%, respectively, of the related consolidated financial statements amounts as of and for the year ended June 30, 2014.

Based on this assessment, our management has concluded that, as of June 30, 2014, 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, 2014. This report, dated August 25, 2014, appears on the following page.

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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, 2014, 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 herein. 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 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, 2014, based on criteria established in Internal Control — Integrated Framework (1992) issued by COSO.

Energy XXI (Bermuda) Limited through its wholly owned subsidiary, Energy XXI Gulf Coast, Inc., acquired EPL Oil and Gas, Inc. on June 3, 2014, and management excluded from its assessment of the effectiveness of Energy XXI (Bermuda) Limited and subsidiaries’ internal control over financial reporting as of June 30, 2014, EPL Oil and Gas Inc.’s internal control over financial reporting. EPL Oil and Gas Inc. represented approximately 47% of assets (net of amounts representing goodwill that are within the scope of the assessment) and 5% of revenues included in the consolidated financial statements of Energy XXI (Bermuda) Limited and subsidiaries as of and for the year ended June 30, 2014. Our audit of internal control over financial reporting of Energy XXI (Bermuda) Limited and subsidiaries also excluded an evaluation of the internal control over financial reporting of EPL Oil and Gas, Inc.

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, 2014 and 2013, 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, 2014, and our report dated August 25, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ UHY LLP
Houston, Texas
August 25, 2014

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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, 2014 and 2013, 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, 2014. Our audit also included the financial statement schedule included in Item 15(a)(2). The Company’s management is responsible for these consolidated financial statements and schedule. Our responsibility is to express an opinion on these consolidated financial statements and schedule 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, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three fiscal years in the period ended June 30, 2014, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

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, 2014, 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 25, 2014 expressed an unqualified opinion on the effective operation of internal control over financial reporting.

/s/ UHY LLP
Houston, Texas
August 25, 2014

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

   
  June 30,
     2014   2013
ASSETS
                 
Current Assets
                 
Cash and cash equivalents   $ 145,806     $  
Accounts receivable
                 
Oil and natural gas sales     167,075       132,521  
Joint interest billings     12,898       9,505  
Insurance and other     5,438       6,745  
Prepaid expenses and other current assets     72,530       50,738  
Deferred income taxes     52,587        
Derivative financial instruments     1,425       38,389  
Total Current Assets     457,759       237,898  
Property and Equipment
                 
Oil and natural gas properties – full cost method of accounting, including $1,165.7 million and $422.6 million of unevaluated properties not being amortized at June 30, 2014 and 2013, respectively     6,524,602       3,289,505  
Other property and equipment     19,760       17,003  
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment     6,544,362       3,306,508  
Other Assets
                 
Goodwill     327,235        
Derivative financial instruments     3,035       21,926  
Equity investments     40,643       12,799  
Restricted cash     6,350        
Other assets and debt issuance costs, net of accumulated amortization     57,394       32,580  
Total Other Assets     434,657       67,305  
Total Assets   $ 7,436,778     $ 3,611,711  
LIABILITIES
                 
Current Liabilities
                 
Accounts payable   $ 415,718     $ 219,610  
Accrued liabilities     133,526       105,192  
Notes payable     21,967       22,524  
Deferred income taxes           20,517  
Asset retirement obligations     79,649       29,500  
Derivative financial instruments     31,957       40  
Current maturities of long-term debt     15,020       19,554  
Total Current Liabilities     697,837       416,937  
Long-term debt, less current maturities     3,744,624       1,350,491  
Deferred income taxes     701,038       140,804  
Asset retirement obligations     480,185       258,318  
Derivative financial instruments     4,306        
Other liabilities     10,958       7,915  
Total Liabilities     5,638,948       2,174,465  

 
 
See accompanying Notes to Consolidated Financial Statements

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

   
  June 30,
     2014   2013
Commitments and Contingencies (Note 15)
                 
Stockholders’ Equity
                 
Preferred stock, $0.001 par value, 7,500,000 shares authorized at June 30, 2014 and 2013, respectively
                 
7.25% Convertible perpetual preferred stock, 8,000 shares issued and outstanding at June 30, 2014 and 2013, respectively            
5.625% Convertible perpetual preferred stock, 812,760 and 813,188 shares issued and outstanding at June 30, 2014 and 2013, respectively     1       1  
Common stock, $0.005 par value, 200,000,000 shares authorized and 93,719,570 and 79,425,473 shares issued and 93,719,570 and 76,485,910 shares outstanding at June 30, 2014 and 2013, respectively     468       397  
Additional paid-in capital     1,837,462       1,512,311  
Accumulated deficit     (19,626 )      (29,352 ) 
Accumulated other comprehensive (loss) income, net of income taxes     (20,475 )      26,552  
Treasury stock, at cost, 2,938,900 shares at June 30, 2013           (72,663 ) 
Total Stockholders’ Equity     1,797,830       1,437,246  
Total Liabilities and Stockholders’ Equity   $ 7,436,778     $ 3,611,711  

 
 
See accompanying Notes to Consolidated Financial Statements

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

     
  Year Ended June 30,
     2014   2013   2012
Revenues
                          
Crude oil sales   $ 1,091,223     $ 1,080,982     $ 1,186,631  
Natural gas sales     139,502       127,863       116,772  
Total Revenues     1,230,725       1,208,845       1,303,403  
Costs and Expenses
                          
Lease operating     365,747       337,163       310,815  
Production taxes     5,427       5,246       7,261  
Gathering and transportation     23,532       24,168       16,371  
Depreciation, depletion and amortization     423,319       376,224       367,463  
Accretion of asset retirement obligations     30,183       30,885       39,161  
General and administrative expense     96,402       71,598       86,276  
Loss (gain) on derivative financial instruments     5,704       1,756       (7,228 ) 
Total Costs and Expenses     950,314       847,040       820,119  
Operating Income     280,411       361,805       483,284  
Other Income (Expense)
                          
Loss from equity method investees     (4,781 )      (6,397 )       
Other income – net     3,298       1,965       71  
Interest expense     (162,728 )      (108,659 )      (108,882 ) 
Total Other Expense     (164,211 )      (113,091 )      (108,811 ) 
Income Before Income Taxes     116,200       248,714       374,473  
Income Tax Expense     57,089       86,633       38,646  
Net Income     59,111       162,081       335,827  
Induced Conversion of Preferred Stock                 6,068  
Preferred Stock Dividends     11,489       11,496       13,028  
Net Income Available for Common Stockholders   $ 47,622     $ 150,585     $ 316,731  
Earnings per Share
                          
Basic   $ 0.64     $ 1.90     $ 4.10  
Diluted   $ 0.64     $ 1.86     $ 3.85  
Weighted Average Number of Common Shares Outstanding
                          
Basic     74,375       79,063       77,310  
Diluted     74,445       87,263       87,208  

 
 
See accompanying Notes to Consolidated Financial Statements

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

     
  Year Ended June 30,
     2014   2013   2012
Net Income   $ 59,111     $ 162,081     $ 335,827  
Other Comprehensive Income (Loss)
                          
Crude Oil and Natural Gas Cash Flow Hedges
                          
Unrealized change in fair value net of ineffective portion     (62,133 )      (7,961 )      228,398  
Effective portion reclassified to earnings during the period     (10,215 )      (39,810 )      (34,418 ) 
Total Other Comprehensive Income (Loss)     (72,348 )      (47,771 )      193,980  
Income Tax Expense (Benefit)     (25,321 )      (16,720 )      67,893  
Net Other Comprehensive Income (Loss)     (47,027 )      (31,051 )      126,087  
Comprehensive Income   $ 12,084     $ 131,030     $ 461,914  

 
 
See accompanying Notes to Consolidated Financial Statements

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

               
               
  Preferred Stock   Common Stock   Treasury Stock   Paid-in Capital   Accumulated (Deficit)   Accumulated Other Comprehensive Income (Loss)   Total
Stockholders’ Equity
  5.625%   7.25%
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  
Common stock issued, net of direct costs                       81                341,478                         341,559  
Common stock based compensation                                         6,711                         6,711  
Repurchase of company common stock                                (170,266 )                                 (170,266 ) 
Treasury stock retired                       (10 )      52,966       (52,956 )                         
Common stock reissued                                189,963       (32,030 )      (3,216 )               154,717  
Discount on convertible debt                                         61,948                         61,948  
Common stock dividends                                                  (34,680 )               (34,680 ) 
Preferred stock dividends                                                  (11,489 )               (11,489 ) 
Comprehensive income                                                  59,111       (47,027 )      12,084  
Balance, June 30, 2014   $ 1               $ 468     $     $ 1,837,462     $ (19,626 )    $ (20,475 )    $ 1,797,830  

 
 
See accompanying Notes to Consolidated Financial Statements

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

     
  Year Ended June 30,
     2014   2013   2012
Cash Flows From Operating Activities
                          
Net income   $ 59,111     $ 162,081     $ 335,827  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                          
Depreciation, depletion and amortization     423,319       376,224       367,463  
Deferred income tax expense     53,448       73,761       38,796  
Change in derivative financial instruments
                          
Proceeds from sale of derivative instruments           760       66,522  
Other – net     (1,793 )      (27,516 )      (52,155 ) 
Accretion of asset retirement obligations     30,183       30,885       39,161  
Loss from equity method investees     4,781       6,397        
Amortization and write-off of debt issuance costs and other     13,774       6,898       7,559  
Stock-based compensation     6,711       3,505       11,760  
Changes in operating assets and liabilities
                          
Accounts receivable     63,283       1,690       (4,995 ) 
Prepaid expenses and other current assets     6,019       12,499       (15,890 ) 
Settlement of asset retirement obligations     (57,391 )      (41,939 )      (14,990 ) 
Accounts payable and accrued liabilities     (55,985 )      32,903       6,456  
Net Cash Provided by Operating Activities     545,460       638,148       785,514  
Cash Flows from Investing Activities
                          
Acquisitions, net of cash acquired     (849,641 )      (161,164 )      (6,401 ) 
Capital expenditures     (788,676 )      (816,105 )      (570,670 ) 
Insurance payments received     1,983             6,472  
Change in equity method investments     (34,294 )      (16,693 )      (2,201 ) 
Proceeds from the sale of properties     126,265             2,750  
Transfer to restricted cash     (325 )             
Other     113       (41 )      457  
Net Cash Used in Investing Activities     (1,544,575 )      (994,003 )      (569,593 ) 
Cash Flows from Financing Activities
                          
Proceeds from the issuance of common and preferred stock, net of offering costs     3,994       7,021       9,839  
Discount on convertible debt allocated to additional paid-in capital     63,432              
Conversion of preferred stock to common stock                 (6,040 ) 
Repurchase of company common stock     (184,263 )      (58,666 )       
Dividends to shareholders – common     (34,680 )      (25,992 )       
Dividends to shareholders – preferred     (11,489 )      (11,496 )      (18,682 ) 
Proceeds from long-term debt     3,420,873       1,576,551       896,717  
Payments on long-term debt     (2,079,485 )      (1,243,848 )      (1,008,300 ) 
Debt issuance costs     (33,461 )      (4,805 )       
Other           3       (775 ) 
Net Cash Provided by (Used in) Financing
Activities
    1,144,921       238,768       (127,241 ) 
Net Increase (Decrease) in Cash and Cash Equivalents     145,806       (117,087 )      88,680  
Cash and Cash Equivalents, beginning of year           117,087       28,407  
Cash and Cash Equivalents, end of year   $ 145,806     $     $ 117,087  

 
 
See accompanying Notes to Consolidated Financial Statements

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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. 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 (Bermuda) Limited 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.

Restricted Cash.  We maintain restricted escrow funds in a trust for future plugging, abandonment and other decommissioning costs. These funds will remain restricted until substantially all required decommissioning is complete. Amounts on deposit in the trust account are reflected in Restricted cash on our consolidated balance sheets.

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, 2014 and 2013, no allowance for doubtful accounts was necessary.

Oil and Natural 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

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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.

We evaluate the impairment of our evaluated oil and natural 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 natural 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 natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural 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.

Weather Based Insurance Linked Securities.  We obtain Weather Based Insurance Linked Securities (“Securities”), to mitigate potential loss to our oil and natural 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 natural 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, vehicle and leasehold improvements 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.

Business Combinations.  For properties acquired in a business combination, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes are recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. Any excess of amounts assigned to assets and liabilities over the purchase price is recorded as a gain on bargain purchase. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.

Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Goodwill.  Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in fiscal 2014 with the EPL Acquisition and has been recorded to our oil and natural gas reporting unit. Events affecting oil and natural gas prices may cause a decrease in the fair value of the reporting unit, and we could have an impairment of goodwill in future periods.

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 directly in earnings.

The net cash flows related to any recognized gains or losses associated with cash flow hedges are reported as oil and natural 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 natural 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 natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural 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

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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, 2014, 2013 and 2012 was $64.5 million, $37.6 million and $38.3 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, 2014 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.

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 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 adopted ASU 2011-11 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

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Note 2 — Recent Accounting Pronouncements  – (continued)

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 accumulated other comprehensive income 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 adopted ASU 2013-02 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

In July 2013 the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU-2013-11). ASU 2013-11 clarifies that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. We are currently evaluating the provisions of ASU 2013-11 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

Note 3 — Acquisitions and Dispositions

ExxonMobil 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 (“ExxonMobil”) 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 ExxonMobil 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. The objective targets at Pendragon well, the initial prospect, were not reached as it encountered mechanical issues and was plugged and abandoned. Subsequently, we began drilling the Merlin well located at Vermilion Block 179; the Merlin well did not encounter any commercial hydrocarbons and was plugged and abandoned. We are currently negotiating an extension of our joint venture with ExxonMobil to further the Pendragon and Merlin wells’ data along with reprocessing the 3D seismic information to determine the future drilling activities on the Vermilion Block.

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 final 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  

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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 final 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 was effective as of 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 final 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 was effective as of January 1, 2013.

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 final 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  

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Note 3 — Acquisitions and Dispositions  – (continued)

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 was effective as of June 1, 2013. We are the operator of these properties.

Revenues and expenses related to the West Delta Interests are 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 final 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  

Black Elk Interest

On December 20, 2013, we closed on the acquisition of certain offshore Louisiana interests in West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC (“Black Elk”) for a total cash consideration of $10.4 million. This acquisition was effective as of October 1, 2013. We are the operator of these properties.

Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of income from December 20, 2013. The acquisition of West Delta 30 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 December 20, 2013 (in thousands):

 
Oil and natural gas properties – evaluated   $ 15,821  
Oil and natural gas properties – unevaluated     6,586  
Asset retirement obligations     (10,503 ) 
Net working capital*     (1,500 ) 
Cash paid   $ 10,404  

* Net working capital includes payables.

Walter Oil & Gas Corporation oil and gas properties interests acquisition

On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation (“Walter”) for a total cash consideration of approximately $22.8 million. This acquisition is effective January 1, 2014 and we are the operator of these properties.

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Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of income from March 7, 2014. The acquisition of South Timbalier 54 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 March 7, 2014 (in thousands):

 
Oil and natural gas properties – evaluated   $ 23,497  
Asset retirement obligations     (705 ) 
Cash paid   $ 22,792  

The fair values of evaluated and unevaluated oil and natural 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 natural 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 (the “Exploration Agreement”) with Apache to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central GoM Shelf. We have a 25% participation interest in the Exploration Agreement, which expires on February 1, 2018.

The area of mutual interest under this Exploration 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 $33.7 million was incurred through June 30, 2014. Drilling on the first well commenced in May 2013 on the southern flank of the salt dome, penetrating eight oil sands and one gas bearing sand. In February 2014 we commenced drilling an offset well which also encountered multiple hydrocarbon bearing sands. Presently both the wellbores have been suspended for future utility and we expect to complete 3D wide azimuth (“WAZ”) seismic data analysis in December 2014. As of June 30, 2014, our share of costs related to these wells was approximately $28.1 million.

Acquisition of EPL Oil & Gas, Inc. (“EPL”)

We acquired EPL on June 3, 2014. The acquisition has been accounted for under the acquisition method, with Energy XXI as the acquirer. EPL is now a wholly-owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”). Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.

In the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash (“Cash Election”), or 1.669 shares of Energy XXI common stock (“Stock Election”) or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock (“Mixed Election” and collectively the (“Merger Consideration”)), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share. Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares shown below, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the

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cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration. As a result, in accordance with the Merger Agreement, 836,311 net exercise shares were converted into $39.00 in cash, without proration.

Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, we issued 23.3 million shares of our common stock and paid approximately $1,012 million in cash. Following is a summary of the total purchase price of approximately $1,504.3 million, including cash acquired of $206.1 million (in millions other than per share amounts):

               
Election   EPL
Shares
  Cash per share   Energy XXI Stock   Cash
Paid
  Energy XXI Stock Issued   Energy XXI Stock Price on June 3, 2014   Cash Value of
Energy XXI Stock Issued
  Total Purchase Price Paid to EPL
Cash Election     30.6     $ 25.92       0.5595     $ 792.6       17.1083     $ 21.11     $ 361.2     $ 1,153.8  
Mixed Election     7.4       25.35       0.5840       186.8       4.3037       21.11       90.8       277.6  
Stock Election     1.1             1.6690             1.9090       21.11       40.3       40.3  
Stock Options     0.8       39.00             32.6                         32.6  
Total     39.9                 $ 1,012.0       23.3210           $ 492.3     $ 1,504.3  

(*) Includes 4.7 million EPL shares held by EPL stockholders that did not make elections prior to the May 30, 2014 election deadline.

The following table summarizes the preliminary purchase price allocation for EPL as of June 3, 2014 (in thousands):

     
  EPL
Historical
  Fair Value Adjustment   Total
     (Unaudited)
Current assets (excluding deferred income taxes)   $ 301,592     $ 1,274     $ 302,866  
Oil and natural gas propertiesa
                          
Evaluated (Including net ARO assets)     1,919,699       112,624       2,032,323  
Unevaluated     41,896       859,886       901,782  
Other property and equipment     7,787             7,787  
Other assets     16,227       (9,002 )      7,225  
Current liabilities (excluding ARO)     (314,649 )            (314,649 ) 
ARO (current and long-term)     (260,161 )      (13,211 )      (273,372 ) 
Debt (current and long-term)     (973,440 )      (52,967 )      (1,026,407 ) 
Deferred income taxesb     (118,359 )      (340,645 )      (459,004 ) 
Other long-term liabilities     (2,242 )      797       (1,445 ) 
Total fair value, excluding goodwill     618,350       558,756       1,177,106  
Goodwillc           327,235       327,235  
Less cash acquired                       206,075  
Total purchase price   $ 618,350     $ 885,991     $ 1,298,266  

a. EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.
b. Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37 percent tax rate, which reflected the 35 percent federal statutory rate and a 2 percent weighted-average of the applicable statutory state tax rates (net of federal benefit).

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c. At June 30, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was unnecessary, and no goodwill impairment was recognized.

EPL’s operating revenues and net income of $60.1 million and $4.2 million for the month ended June 30, 2014 are included in the Consolidated Statement of Income for the year ended June 30, 2014.

In accordance with the acquisition method of accounting, the purchase price from our acquisition of EPL has been allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to quoted market prices, where available; expected future cash flows based on estimated reserve quantities; estimated costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates, and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed has been recorded as goodwill. Goodwill recorded in connection with the acquisition is not deductible for income tax purposes.

The final valuation of assets acquired and liabilities assumed is not complete and the net adjustments to those values may result in changes to goodwill and other carrying amounts initially assigned to the assets and liabilities based on the preliminary fair value analysis. The principal remaining items to be valued are tax assets and liabilities, and any related valuation allowances, which will be finalized in connection with the filing of related tax returns.

The fair value measurements of the oil and natural gas properties and the asset retirement obligations included in other long-term liabilities were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value measurement of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.

Goodwill primarily resulted from the requirement to recognize deferred taxes on the difference between the fair value and the historical tax basis of the acquired assets.

Costs associated with the EPL Acquisition totaled $13.6 million for the year ended June 30, 2014, which were included in general and administrative expenses in the consolidated statements of income.

The following supplemental unaudited pro forma consolidated financial information has been prepared to reflect the EPL Acquisition as if the merger had occurred on July 1, 2012. The unaudited pro forma financial information combines the historical statements of income of Energy XXI and EPL for the years ended June 30, 2014 and 2013.

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Note 3 — Acquisitions and Dispositions  – (continued)

The historical consolidated financial information has been adjusted to reflect factually supportable items that are directly attributable to the acquisition (in thousands, except per share amounts).

   
  Years Ended
June 30,
     2014   2013
     (Unaudited)
Revenues   $ 1,860,200     $ 1,927,235  
Operating income     277,904       512,869  
Net income (loss) from continuing operations     (7,017 )      202,904  
Net income (loss) available to Energy XXI common stockholders     (18,506 )      191,408  
Net income (loss) per share available to Energy XXI common stockholders:
                 
Basic   $ (0.16 )    $ 1.87  
Diluted     (0.16 )      1.83  

The above supplemental unaudited pro forma consolidated financial information has been prepared for illustrative purposes only and is not intended to be indicative of the results of operations that actually would have occurred had the acquisition occurred on July 1, 2012, nor is such information indicative of any expected results of operations in future periods. The most significant pro forma adjustments to income from continuing operations for the year ended June 30, 2014, were the following:

a. Exclude $43.3 million of EPL’s exploration costs, impairment expense and gain on sales of assets accounted for under the successful efforts method of accounting to correspond with EXXI’s full cost method of accounting.
b. Increase DD&A expense by $64.2 million for the EPL Properties to correspond with EXXI’s full cost method of accounting.
c. Increase interest expense by $47.8 million to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under EXXI’s revolving credit facility for approximately eleven months ended June 3, 2014. Decrease interest expense $13.7 million to reflect non-cash interest expense associated with the $510 million of EPL’s 8.25% Senior Notes due to the adjustment to fair value of the assumed EPL debt obligations.

The most significant pro forma adjustments to income from continuing operations for the year ended June 30, 2013, were the following:

a. Include net earnings of $57.6 million which represents incremental revenues, lease operating and other direct operating expenses related to EPL’s acquisitions and divestitures from July 1, 2012 to the date of such transactions.
b. Increase DD&A expense by $116.0 million for the EPL Properties to correspond with EXXI’s full cost method of accounting.
c. Increase interest expense by $51.9 million to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under EXXI’s revolving credit facility for the twelve months ending June 30, 2013. Decrease interest expense $7.0 million to reflect non-cash interest expense associated with the $510 million of EPL’s 8.25% Senior Notes due to the adjustment to fair value of the assumed EPL debt obligations, net of interest expense of $5.4 million to reflect interest on the 8.25% Senior Notes from July 1, 2012.

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Sale of Oil and Natural Gas properties interests

On April 1, 2014, we closed on the sale of our interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of our equity method investee, Energy XXI M21K, LLC (“EXXI M21K”), for cash consideration of approximately $122.9 million. Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $124.4 million, which is subject to customary closing adjustments.

Sale of Oil and Gas properties interests in South Pass 49 field

On June 3, 2014, Energy XXI GOM, LLC, (“EXXI GOM”) our wholly owned indirect subsidiary closed on the sale of its 100% interests in South Pass 49 field to EPL, which is our wholly owned indirect subsidiary, for cash consideration of approximately $230 million. As this transaction is between our two wholly owned indirect subsidiaries, there is no impact on a consolidated basis to our revenues and expenses or the full cost pool related to this transaction.

Note 4 — Property and Equipment

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

   
  June 30,
     2014   2013
Oil and natural gas properties
                 
Proved properties   $ 8,247,352     $ 5,335,737  
Less: accumulated depreciation, depletion, amortization and impairment     2,888,451       2,468,783  
Proved properties     5,358,901       2,866,954  
Unevaluated properties     1,165,701       422,551  
Oil and natural gas properties     6,524,602       3,289,505  
Other property and equipment     39,272       32,786  
Less: accumulated depreciation     19,512       15,783  
Other property and equipment     19,760       17,003  
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment   $ 6,544,362     $ 3,306,508  

The following table summarizes an aging of total costs related to unevaluated properties and wells in progress excluded from the amortization base as of June 30, 2014 (in thousands).

         
  Net Costs Incurred During the Years Ended June 30,   Balance as of June 30, 2014
     2011 and prior   2012   2013   2014
Unevaluated Properties (acquisition costs)   $ 38,289     $     $ 51,435     $ 890,696     $ 980,420  
Wells in Progress (exploratory costs)     122,724       89,611       120,492       (147,546 )      185,281  
     $ 161,013     $ 89,611     $ 171,927     $ 743,150     $ 1,165,701  

The Company’s investment in unevaluated properties primarily relates to the unevaluated oil and gas properties acquired in oil and gas property acquisitions, exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. Costs associated with these

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unevaluated properties are transferred to evaluated properties upon the earlier of (i) when a determination is made whether there are any proved reserves related to the properties, or (ii) amortized over a period of time of not more than four years.

Exploratory wells in progress include $185.3 million in costs related to our participation with Freeport-McMoRan, Inc. who operates several prospects in the ultra-deep shelf and onshore area (“ultra-deep trend”) in the Gulf of Mexico. Activities related to certain of these well operations are controlled by the operator and these wells may have continued drilling and completion activities or, may require development of specialized equipment necessary to complete and test these wells for production.

As of June 30, 2014, the costs associated with our major projects and their status was as follows (in millions):

   
Project Name   Cost   Status
Davy Jones Facilities   $ 22.1       Facilities cost in Davy Jones field for well
operations.
 
Davy Jones Offset Appraisal Well     69.8       Davy Jones Offset Appraisal Well is awaiting test of Wilcox sands.  
Blackbeard East     50.8       Plans to complete into the Miocene Sands in
late 2015.
 
Lomond North     42.6       Completion operations in progress to test
lower Wilcox and Cretaceous objectives.
 
Total   $ 185.3        

Note 5 — Equity Method Investments

20% interest in Energy XXI M21K, LLC

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 natural 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 was 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 established 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 a 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 natural gas fields owned by LLOG Exploration. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was

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$103 million. The effective date of the acquisition was April 1, 2013. In connection with this acquisition, M21K paid LLOG Exploration a performance deposit of $10.3 million. On August 30, 2013, M21K closed on the acquisition and paid the remaining purchase price of $70.5 million to LLOG Exploration. Our share of the purchase price was approximately $16.2 million.

On September 17, 2013, M21K entered into a waiver and consent to the M21K First Lien Credit Agreement that allows a one-time distribution of funds from M21K to its parent on or after November 1, 2013, subject to certain liquidity requirements, and increased the borrowing base to $40 million.

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

Energy XXI Gulf Coast, Inc. (“EGC”), our wholly owned subsidiary, receives a management fee from M21K for providing administrative assistance in carrying out its operations. See Note 13 — Related Party Transactions of Notes to Consolidated Financial Statements in this Form 10-K.

The provisions of the M21K Limited Liability Company Agreement (“LLC Agreement”) provide that M21K can make acquisitions subject to the commitment of its partners. While it is envisioned that M21K will be sold eventually to a third party to monetize returns from the investments, the M21K LLC Agreement does provide for a put and a call that can occur starting July 19, 2016; subject to an earlier option if there is a change of control of Energy XXI.

On April 1, 2014, M21K closed on the acquisition of certain interests in Eugene Island 330 and South Marsh Island 128 fields (“the Acquired Properties”) from Energy XXI, for cash consideration of approximately $122.9 million. Energy XXI has provided a guarantee for asset retirement obligations related to the Acquired Properties. This acquisition is subject to customary closing adjustments.

As of June 30, 2014, our investment in EXXI M21K was approximately $40.6 million and we incurred $3.5 million and $2.9 million in equity loss in the years ended June 30, 2014 and 2013, respectively.

80% interest in Ping Energy XXI Limited (“Ping Energy”)

Our wholly-owned subsidiary Energy XXI International Limited (“EXXI International”), pursuant to a Joint Development Agreement (“JDA”) held a 49% interest in Ping Energy, which was active in the pursuit to identify and acquire exploratory, developmental and producing oil and natural gas properties in South East Asia.

On October 18, 2013, EXXI International amended the JDA and increased its ownership interest to 80% in Ping Energy, subsequent to which all the operations in Ping Energy were consolidated in our financial statements, effective October 1, 2013.

We incurred $1.2 million equity loss through September 30, 2013 and had incurred $3.5 million in equity loss in the year ended June 30, 2013.

In January 2014, EXXI International terminated the JDA with Ping Energy and is in the process of dissolving Ping Energy.

Subsequent to our EPL Acquisition, as disclosed in Note 3 — Acquisitions and Dispositions of Notes to Consolidated Financial Statement in this Form 10-K, we presently do not intend to pursue any international opportunities to acquire exploratory, development or producing oil and natural gas properties.

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Note 6 — Long-Term Debt

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

   
  June 30,
     2014   2013
Revolving credit facility   $ 689,000     $ 339,000  
9.25% Senior Notes due 2017     750,000       750,000  
8.25% Senior Notes due 2018     510,000        
7.75% Senior Notes due 2019     250,000       250,000  
7.5% Senior Notes due 2021     500,000        
6.875% Senior Notes due 2024     650,000        
3.0% Senior Convertible Notes due 2018     400,000        
Original issue discount, 3.0% Senior Convertible Notes due 2018     (57,014 )       
4.14% Promissory Note due 2017     4,774       5,187  
Debt premium, 8.25% Senior Notes due 2018(1)     40,566        
Derivative instruments premium financing     21,000       24,681  
Capital lease obligations     1,318       1,177  
Total debt     3,759,644       1,370,045  
Less current maturities     15,020       19,554  
Total long-term debt   $ 3,744,624     $ 1,350,491  

(1) Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition at their fair value at June 3, 2014.

Maturities of long-term debt as of June 30, 2014 are as follows (in thousands):

 
Year Ending June 30,  
2015   $ 15,020  
2016     7,844  
2017     751  
2018     1,993,043  
2019     592,986  
Thereafter     1,150,000  
Total   $ 3,759,644  

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by EGC, in May 2011 and underwent its Eighth Amendment on June 3, 2014 as noted below. This facility, as amended, has lender commitments of $1.7 billion and matures on April 9, 2018, provided that the facility will mature immediately if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Borrowings are limited to a borrowing base of $1.5 billion, which is based on oil and natural gas reserve values which are re-determined 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. The First Lien Credit Agreement, as amended, requires the consolidated 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

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interest coverage ratio to be less than 3.0 to 1.0, and (c) EGC’s current ratio (in each case as defined in the First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, 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.

On September 27, 2013, EGC entered into the Sixth Amendment (the “Sixth Amendment”) to the First Lien Credit Agreement. Under the Sixth Amendment, the borrowing base for EGC was increased from $850 million to $1,087.5 million. Additionally, the Sixth Amendment provided EGC the ability to specify interest periods for LIBOR loans of less than a month in length and made some related adjustments to the definition of LIBOR and other technical corrections.

On April 7, 2014, EGC entered into the Seventh Amendment (the “Seventh Amendment”) to the First Lien Credit Agreement. Under the Seventh Amendment, the borrowing base for EGC was increased from $1,087.5 million to $1,200 million. Additionally, the Seventh Amendment incorporated the 7.50% Senior Notes due 2021 as senior unsecured debt generally permitted under the terms of the First Lien Credit Agreement, so that provisions under the First Lien Credit Agreement for such notes are commensurate with the provisions already existing for EGC’s 9.25% senior unsecured notes due 2017 and 7.75% senior unsecured notes due 2019. Also, the Seventh Amendment allowed for the incurrence of an additional $1,000 million of unsecured debt, subject to certain conditions, including that the minimum liquidity requirements outlined in the First Lien Credit Agreement would be increased in the amount of 25% of any such new debt incurred until such time as the lenders under the First Lien Credit Agreement otherwise provide or waive such increase.

On June 3, 2014, EGC entered into the Eighth Amendment (“the Eighth Amendment”) to the First Lien Credit Agreement. Pursuant to the Eighth Amendment, the borrowing base for EGC was established at $1.5 billion (an increase from $1.2 billion as determined on April 7, 2014) until the next redetermination of such borrowing base pursuant to the terms of the First Lien Credit Agreement. Of this borrowing base amount, EGC established a sub-facility pursuant to the Eighth Amendment for its wholly owned subsidiary, EPL, with a borrowing base of $475 million for such sub-facility. Upon the effectiveness of the Eighth Amendment, EPL immediately borrowed the entire $475 million to refinance the outstanding indebtedness it had under the terms of a credit agreement in existence at the effective time of the acquisition of EPL by EGC. The borrowing base for this sub-facility is subject to redeterminations from time to time generally on the same basis as is the overall borrowing base under the First Lien Credit Agreement. Under the Eighth Amendment, EGC and its subsidiaries, other than EPL and its subsidiaries, have guaranteed and secured the indebtedness of EPL and its subsidiaries, but EPL and its subsidiaries have not commensurately guaranteed the obligations of EGC and its other subsidiaries. However, per the terms of the First Lien Credit Agreement, immediately upon EPL’s retirement of its obligations in respect of its outstanding 8.25% Senior Notes due 2018, EPL and its subsidiaries are required to guarantee and secure the obligations generally of EGC and its subsidiaries and such EPL sub-facility shall terminate and the entire borrowing base amount shall thereupon be available to EGC for credit extensions under the terms of the First Lien Credit Agreement. Most of the terms of the Eighth Amendment generally are in regards to incorporating the concept of EPL as a separate “borrower” for purposes of the First Lien Credit Agreement. Interest accrues and is payable on the EPL sub-facility on the same basis as principal amounts outstanding generally under the First Lien Credit Agreement.

The Eighth Amendment also incorporates a few additional changes, including the incorporation of the concept of EGC’s 6.875% Senior Notes due 2024 and EPL’s 8.25% Senior Notes due 2018 as senior unsecured debt generally permitted under the terms of the First Lien Credit Agreement, so that provisions under the First Lien Credit Agreement for such notes are commensurate with the provisions already existing for EGC’s 9.25% senior unsecured notes due 2017, 7.75% senior unsecured notes due 2019 and 7.50% senior

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unsecured notes due 2021. With the Eighth Amendment, EGC retains the ability to further incur $1 billion of permitted unsecured indebtedness, still subject to the condition that the minimum liquidity requirements outlined in the First Lien Credit Agreement would be increased in the amount of 25% of any such new debt incurred until such time as the lenders under the First Lien Credit Agreement otherwise provide or waive such increase. Furthermore, the Eighth Amendment removed the prohibition on the prepayment, redemption or other refinance of EGC’s outstanding 9.25% senior unsecured notes due 2017, 7.75% senior unsecured notes due 2019, 7.50% senior unsecured notes due 2021 and the 6.875% Senior Notes due 2024 and any other permitted unsecured indebtedness incurred by EGC, and instead established certain quantitative liquidity conditions to making any such prepayment, redemption or other refinance of such senior unsecured notes or other permitted unsecured indebtedness. Pursuant to the Eighth Amendment, EGC is permitted to use proceeds from the issuance of further permitted unsecured indebtedness to prepay, redeem or refinance such notes and, upon such action, treat such amount so used as a refinancing of the amount so prepaid redeemed, and restore the availability to incur such amount under the permitted unsecured indebtedness basket.

As of June 30, 2014, EGC was in compliance with the covenants described above and the other financial covenants under the First Lien Credit Agreement, with the possible exception of its total leverage ratio. EGC typically completes its audit after the Bermuda parent company completes its audit. Based upon preliminary calculations, EGC determined it may have exceeded the total leverage ratio covenant and therefore EGC sought a temporary increase in the total leverage ratio covenant. EGC’s total leverage ratio covenant included within Section 7.2.4(a) of the First Lien Credit Agreement requires EGC to maintain a Total Leverage Ratio (as defined therein) of not more than 3.5 to 1.0 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC’s leverage ratio was estimated to be 3.6 to 1.0 for the quarter ended June 30, 2014. EGC received a waiver from the lenders under the First Lien Credit Agreement on August 22, 2014 with respect to this potential violation for the quarters ending June 30, 2014 and September 30, 2014. The waiver is conditioned upon EGC maintaining a Total Leverage Ratio of not more than 4.25 to 1.00 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC was in compliance with the requirements under the waiver for the fiscal quarter ended June 30, 2014 and expects to be in compliance therewith for the fiscal quarter ended September 30, 2014. EGC is currently in discussions with the lenders under the First Lien Credit Agreement to amend certain of the financial covenants in order to ensure that EGC will be in compliance with the covenants for the remainder of the 2015 fiscal year. There is no assurance that EGC will reach agreement with its lenders on these amendments. In the event an amendment cannot be obtained, EGC believes that it will be able to comply with the current covenants under the First Lien Credit Agreement through June 30, 2015 by taking certain actions within EGC’s control.

As of June 30, 2014, EGC had $689 million in borrowings and $225.7 million in letters of credit issued under our First Lien Credit Agreement.

High Yield Facilities

8.25% Senior Notes Due 2018

On June 3, 2014, EGC assumed the 8.25% Senior Notes in EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee (the “8.25% Senior Notes Trustee”), governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of consents from the requisite holders of the 8.25% Senior Notes in accordance with the terms and conditions of the Consent Solicitation Statement dated April 7, 2014, pursuant to which we had solicited consents (the “Consent Solicitation”) from the holders of the 8.25% Senior Notes to make certain proposed amendments to certain

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definitions set forth in the Indenture (the “Proposed COC Amendments”), as reflected in the Supplemental Indenture. The Consent Solicitation was made as permitted by the Merger Agreement. On April 18, 2014, we had received valid consents from holders of an aggregate principal amount of $484.1 million of the 8.25% Senior Notes and that those consents had not been revoked prior to the Consent Time. As a result, the requisite holders of the 8.25% Senior Notes had consented to the Proposed COC Amendments, upon the terms and subject to the conditions set forth in the Consent Solicitation Statement. Accordingly, EPL, the guarantors party thereto and the Trustee entered into the Supplemental Indenture. Subject to the terms and conditions set forth in the Statement, we paid an aggregate cash payment equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents to the Proposed COC Amendments were validly delivered and unrevoked.

EGC believes that the fair value of the $510 million of 8.25% Senior Notes outstanding as of June 30, 2014 was $545.7 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

6.875% Senior Notes Due 2024

On May 27, 2014, EGC issued $650 million face value of 6.875%, unsecured senior notes due March 15, 2024 at par (“6.875% Senior Notes”). Presently, the 6.875% Senior Notes are not registered under the Securities Act, however EGC and its guarantors have agreed, pursuant to a registration rights agreement with the initial purchasers of the 6.875% Senior Notes, to file a registration statement with the Securities and Exchange Commission (“SEC”) with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 365 days after the issue date of the 6.875% Senior Notes. EGC incurred underwriting and direct offering costs of approximately $11 million which have been capitalized and will be amortized over the life of the 6.875% Senior Notes.

On or after March 15, 2019, EGC will have the right to redeem all or some of the 6.875% Senior Notes at specified redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption shall be made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 6.875% Senior Notes.

The indenture governing the 6.875% Senior Notes will, among other things, limit EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

EGC believes that the fair value of the $650 million of 6.875% Senior Notes outstanding as of June 30, 2014 was $663 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 6.875% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

3.0% Senior Convertible Notes due 2018

On November 18, 2013, the Company sold $400 million face value of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). The Company incurred underwriting and direct offering costs of $7.6 million which have been capitalized and will be amortized over the life of the 3.0% Senior Convertible Notes. The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the Company’s election, based on an initial conversion rate of 24.7523 shares of common stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common stock). The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.

Upon conversion, the Company will be obligated to pay or deliver, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at its election. If the Company satisfies its conversion obligation solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture governing the 3.0% Senior Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture governing the 3.0% Senior Convertible Notes). Upon any conversion, subject to certain exceptions, holders of the 3.0% Senior Convertible Notes will not receive any cash payment representing accrued and unpaid interest. Instead, interest will be paid by the cash, shares of common stock or a combination of cash and shares of common stock paid or delivered, as the case may be, upon conversion of a convertible note.

If holders elect to convert the notes in connection with certain fundamental change transactions described in the indenture governing the 3.0% Senior Convertible Notes, the Company will increase the conversion rate by a number of additional shares determined by reference to the provisions contained in the indenture governing the 3.0% Senior Convertible Notes based on the effective date of, and the price paid (or deemed paid) per share of common stock in, such make-whole fundamental change. If holders of common stock receive only cash in connection with certain make-whole fundamental changes, the price paid (or deemed paid) per share will be the cash amount paid per share. Otherwise, the price paid (or deemed paid) per share will be equal to the average of the closing sale prices of common stock on the five trading days prior to, but excluding, the effective date of such make-whole fundamental change.

If the Company undergoes a fundamental change (as defined in the indenture governing the 3.0% Senior Convertible Notes) prior to maturity, holders of the 3.0% Senior Convertible Notes will have the right, at their option, to require the Company to repurchase for cash some or all of their notes at a repurchase price equal to 100% of the principal amount of the notes being repurchased, plus accrued and unpaid interest (including additional interest, if any) to, but excluding, the fundamental change repurchase date.

For accounting purposes, the $400 million aggregate principal amount of 3% Senior Convertible Notes for which we received cash was recorded at fair market value by applying the implied straight debt rate of 6.75% to allocate the proceeds between the debt component and the convertible equity component of the 3% Senior Convertible Notes. Based on applying the implied straight debt rate, the $400 million aggregate principal amount of the 3% Senior Convertible Notes was recorded at $336.6 million and the $63.4 million original issue discount will be amortized as an increase in interest expense over the life of the 3% Senior Convertible Notes.

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The Company believes that the fair value of the $400 million of 3.0% Senior Convertible Notes, including the equity conversion feature, outstanding as of June 30, 2014 was $396.8 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

7.5% Senior Notes Due 2021

On September 26, 2013, EGC issued $500 million face value of 7.5%, unsecured senior notes due December 15, 2021 at par (“7.5% Senior Notes”). Presently, the 7.5% Senior Notes are not registered under the Securities Act, however EGC and its guarantors will agree, pursuant to a registration rights agreement with the initial purchasers of the 7.5% Senior Notes, to file a registration statement with the SEC with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 7.50% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 270 days after the issue date of the 7.5% Senior Notes. In April 2014, we filed Amendment No. 1 to the registration statement for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes with the SEC, the registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014. EGC incurred underwriting and direct offering costs of $8.6 million which have been capitalized and will be amortized over the life of the 7.5% Senior Notes.

On or after December 15, 2016, EGC will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, EGC may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, EGC may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 7.5% Senior Notes.

The indenture governing the 7.5% Senior Notes will, among other things, limit EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

EGC believes that the fair value of the $500 million of 7.5% Senior Notes outstanding as of June 30, 2014 was $541.3 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 7.5% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

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.

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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, 2014 was $806.6 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, 2014 was $269.5 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.

Guarantee of Securities Issued by EGC

Our indirect, wholly-owned subsidiary, EGC, is the issuer of each of the 6.875% Senior Notes, 7.5% Senior Notes, 9.25% Senior Notes and 7.75% Senior Notes, which are fully and unconditionally guaranteed by the Bermuda parent company and each of EGC’s existing and future material domestic subsidiaries. The Bermuda parent company and its subsidiaries, other than EGC, have no significant independent assets or operations. EGC is permitted to make dividends and other distributions subject to certain limitations as more fully disclosed in this note above under the caption “Revolving Credit Facility”.

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Note 6 — Long-Term Debt  – (continued)

4.14% 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 rate of 4.14% per annum.

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase from our hedge counterparties. Substantially all of our hedges are 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, 2014 and June 30, 2013, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $21 million and $24.7 million, respectively.

Interest Expense

For the years ended June 30, 2014, 2013 and 2012, interest expense consisted of the following (in thousands):

     
  Year Ended June 30,
     2014   2013   2012
Revolving credit facility   $ 13,956     $ 11,816     $ 9,420  
9.25% Senior Notes due 2017     69,375       69,375       69,375  
8.25% Senior Notes due 2018     3,507              
7.75% Senior Notes due 2019     19,375       19,375       19,375  
7.5% Senior Notes due 2021     28,542              
6.875% Senior Notes due 2024     4,096              
3% Senior Convertible Notes due 2018     7,266              
3.14% Promissory Note due 2017     210              
Amortization of debt issue cost – Revolving credit facility     3,076       4,303       4,881  
Amortization of debt issue cost – 9.25% Senior Notes
due 2017
    2,206       2,206       2,206  
Amortization of fair value premium – 8.25% Senior Notes due 2018     (841 )             
Amortization of debt issue cost – 7.75% Senior Notes
due 2019
    388       388       388  
Amortization of debt issue cost – 7.50% Senior Notes
due 2021
    783              
Amortization of debt issue cost – 6.875% Senior Notes
due 2022
    102              
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018     6,418              
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018     801              
Derivative instruments premium financing and other     987       1,196       1,347  
Bridge commitment fee     2,481              
Settlement of Lehman Brothers liability                 1,890  
     $ 162,728     $ 108,659     $ 108,882  

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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 bore interest at an annual rate of 1.774%. The note matured and was repaid on October 23, 2013.

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 bore interest at an annual rate of 1.623%. The note matured and was repaid on April 26, 2014.

On June 3, 2014, 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 $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015. The balance outstanding as of June 30, 2014 was $22.0 million.

Note 8 — Asset Retirement Obligations

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

   
  Year Ended June 30,
     2014   2013
Balance at beginning of year   $ 287,818     $ 301,415  
Liabilities acquired     284,661       7,277  
Liabilities incurred and true up to liabilities settled     41,216       18,486  
Liabilities settled     (57,391 )      (41,939 ) 
Revisions in estimated cash flows     (26,653 )      (28,306 ) 
Accretion expense     30,183       30,885  
Total balance at end of year     559,834       287,818  
Less current portion     79,649       29,500  
Long-term balance at end of year   $ 480,185     $ 258,318  

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.

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Note 9 — Derivative Financial Instruments  – (continued)

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX 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. In April 2014 we began including Argus-LLS futures collars in our hedging portfolio to appropriately align and manage our exposure and price risk to market conditions.

Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges and expect to carry those hedges through the end of contract term beginning from June 2014 through December 2015. EPL’s oil contracts are primarily swaps and benchmarked to Argus-LLS and Brent.

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, 2014, all of the monetized amounts remaining in OCI were recognized in income.

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 were recognized in income over the life of the underlying hedge contracts through December 31, 2013. As of June 30, 2014, all of the amounts remaining in deferred hedge revenue were recognized in income.

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Note 9 — Derivative Financial Instruments  – (continued)

As of June 30, 2014, 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 2014 – December 2014     Three-Way Collars       Oil-Brent-IPE       766              $ 69.00     $ 89.00     $ 124.99  
July 2014 – December 2014     Put Spreads       Oil-Brent-IPE       431                66.43       86.43           
July 2014 – December 2014     Collars       Oil-Brent-IPE       368                         90.00       108.38  
July 2014 – December 2014     Put Spreads       NYMEX-WTI       1,230                70.00       90.00           
July 2014 – December 2014     Put       NYMEX-WTI       460                         90.00           
July 2014 – December 2014     Roll Swap       NYMEX-WTI       2,295     $ 1.03                             
July 2014 – December 2014     Three-Way Collars       NYMEX-WTI       610                70.00       90.00       137.20  
July 2014 – December 2014     Swaps       ARGUS-LLS       1,614       92.84                             
January 2015 – December 2015     Three-Way Collars       Oil-Brent-IPE       3,650                71.00       91.00       113.75  
January 2015 – December 2015     Swaps       Oil-Brent-IPE       548       97.70                             
January 2015 – December 2015     Collars       ARGUS-LLS       1,825                         80.00       123.38  
January 2015 – December 2015     Put       NYMEX-WTI       1,813                         88.76           
January 2015 – December 2015     Roll Swap       NYMEX-WTI       3,180       1.03                             

As of June 30, 2014, we had the following net open natural gas derivative positions:

             
          Weighted Average Contract Price
           Swaps   Collars/Put Spreads
Period   Type of Contract   Index   Volumes (MMBtu)   Fixed Price   Sub Floor   Floor   Ceiling
July 2014 – December 2014     Three-Way Collars       NYMEX-HH       8,187              $ 3.36     $ 4.00     $ 4.60  
July 2014 – December 2014     Put Spreads       NYMEX-HH       1,013                3.25       4.00           
July 2014 – December 2014     Swaps       NYMEX-HH       920     $ 4.01                             
January 2015 – December 2015     Swaps       NYMEX-HH       1,570       4.31                             

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

               
               
  Asset Derivative Instruments   Liability Derivative Instruments
     June 30, 2014   June 30, 2013   June 30, 2014   June 30, 2013
     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     $ 16,829       Current     $ 52,216       Current     $ 47,912       Current     $ 14,609  
       Non-Current       9,595       Non-Current       42,263       Non-Current       10,866       Non-Current       20,337  
Commodity Derivative Instruments not designated as hedging instruments:
                                                                       
Derivative financial instruments     Current       551       Current       1,976       Current             Current       1,234  
       Non-Current             Non-Current             Non-Current             Non-Current        
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement           26,975             96,455             58,778             36,180  
Derivative financial instruments     Current       (15,955 )      Current       (15,803 )      Current       (15,955 )      Current       (15,803 ) 
       Non-Current       (6,560 )      Non-Current       (20,337 )      Non-Current       (6,560 )      Non-Current       (20,337 ) 
Gross amounts offset in Balance Sheet           (22,515 )            (36,140 )            (22,515 )            (36,140 ) 
Net amounts presented in Balance Sheet     Current       1,425       Current       38,389       Current       31,957       Current       40  
       Non-Current       3,035       Non-Current       21,926       Non-Current       4,306       Non-Current        
           $ 4,460           $ 60,315           $ 36,263           $ 40  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

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

     
  Year Ended June 30,
     2014   2013   2012
Location of (Gain) Loss in Income Statement
                          
Cash Settlements, net of amortization of purchased put premiums:
                          
Oil sales   $ 12,985     $ (13,296 )    $ (438 ) 
Natural gas sales     (3,619 )      (15,110 )      (28,164 ) 
Total cash settlements     9,366       (28,406 )      (28,602 ) 
Commodity Derivative Instruments designated as hedging instruments:
                          
(Gain) loss on derivative financial instruments
                          
Ineffective portion of commodity derivative instruments     6,339       881       (3,479 ) 
Commodity Derivative Instruments not designated as hedging instruments:
                          
(Gain) loss on derivative financial instruments
                          
Realized mark to market (gain) loss     (1,065 )      1,686       (4,542 ) 
Unrealized mark to market (gain) loss     430       (811 )      793  
Total (gain) loss on derivative financial instruments     5,704       1,756       (7,228 ) 
Total (gain) loss   $ 15,070     $ (26,650 )    $ (35,830 ) 

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, 2014
                          
Commodity Derivative Instruments   $ 47,027                    
Revenues            $ (6,640 )          
Loss (gain) on derivative financial instruments                     $ 6,339  
Total   $ 47,027     $ (6,640 )    $ 6,339  
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  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

     
Location of (Gain) Loss   Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax
(Effective Portion)
  Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax
(Effective Portion)
  Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Year Ended June 30, 2012
                          
Commodity Derivative Instruments   $ (126,087 )                   
Revenues            $ (22,372 )          
Loss (gain) on derivative financial instruments                     $ (3,479 ) 
Total   $ (126,087 )    $ (22,372 )    $ (3,479 ) 

Components of AOCI representing all of the reclassifications out of AOCI to income for the periods presented (in thousands):

     
  Before Tax   After Tax   Location Where Consolidated Net Income is Presented
Year ended June 30, 2014
                          
Unrealized gain on derivatives at beginning of the year   $ (40,851 )    $ (26,552 )          
Unrealized change in fair value during the year     55,794       36,266           
Ineffective portion reclassified to earnings during the year     6,339       4,121       Loss on derivative financial instruments  
Realized amounts reclassified to earnings during the year     10,215       6,640       Revenues  
Unrealized loss on derivatives at end of the year   $ 31,497     $ 20,475        

     
  Before Tax   After Tax   Location Where Consolidated Net Income is Presented
Year ended June 30, 2013
                          
Unrealized gain on derivatives at beginning of the year   $ (88,620 )    $ (57,603 )          
Unrealized change in fair value during the year     7,078       4,601           
Ineffective portion reclassified to earnings during the year     881       573       Loss on derivative financial instruments  
Realized amounts reclassified to earnings during the year     39,810       25,877       Revenues  
Unrealized gain on derivatives at end of the year   $ (40,851 )    $ (26,552 )       

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

     
  Before Tax   After Tax   Location Where Consolidated Net Income is Presented
Year ended June 30, 2012
                          
Unrealized loss on derivatives at beginning of the year   $ 105,360     $ 68,484           
Unrealized change in fair value during the year     (224,919 )      (146,197 )          
Ineffective portion reclassified to earnings during the year     (3,479 )      (2,261 )      Loss on derivative financial instruments  
Realized amounts reclassified to earnings during the year     34,418       22,371       Revenues  
Unrealized gain on derivatives at end of the year   $ (88,620 )    $ (57,603 )       

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $24.9 million ($16.2 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, 2014, 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, and paid quarterly cash dividends of $0.12 per share to holders of our common stock on June 14, 2013, September 13, 2013, December 13, 2013, March 14, 2014 and June 13, 2014, to shareholders of record on May 31, 2013, August 30, 2013, November 29, 2013, February 28, 2014 and May 30, 2014, respectively.

On July 16, 2014, 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 12, 2014 to shareholders of record on August 29, 2014.

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

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Note 10 — Stockholders’ Equity  – (continued)

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 on our 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.

Pursuant to the stock repurchase program approved by our Board of Directors in May 2013, during the year ended June 30, 2014, we incurred $94.2 million to repurchase 3,700,463 shares of our common stock at a weighted average price per share, excluding fees, of $25.45 and 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. As of June 30, 2014, $83.2 million remains available for repurchase under the share repurchase program.

In addition, concurrently with the offering of our 3.0% Senior Convertible Notes in November 2013, one of the Company’s wholly-owned subsidiary repurchased 2,776,200 shares of the Company’s common stock for approximately $76 million, at a weighted average price per share, excluding fees of $27.39.

In February 2014, we retired 2,087,126 shares of our common stock, resulting in 7,329,100 shares of common stock being held in treasury. The entire 7,329,100 shares of common stock in treasury were reissued on June 3, 2014 as part of our common stock issued to EPL stockholders upon merger.

As discussed in Note 6 — Long-Term Debt of Notes to Consolidated Financial Statements in this Form 10-K, in November 2013, we sold $400 million of 3% Senior Convertible Notes. The $63.4 million allocated to the equity portion of the 3% Senior Convertible Notes, less offering costs of $1.4 million, were recorded as an increase in additional paid in capital.

As discussed in Note 3 — Acquisitions and Dispositions of Notes to Consolidated Financial Statements in this Form 10-K, upon closing of the EPL Acquisition, we issued 23,320,955 of our common stock, including the reissue of our common stock held in treasury as noted above towards the stock component of the EPL purchase price.

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.

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 our common stock, or a combination thereof. If we elect to make payments in shares of common stock, such shares shall be valued for such purposes at 95% of the market value of our 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, 2014, we canceled and converted a total of 428 shares of our 5.625% Preferred Stock into a total of 4,288 shares of common stock using a conversion rate ranging from 10.0147 to 10.0579 common shares per preferred share and 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 — Stockholders’ Equity  – (continued)

The 5.625% Preferred Stock became callable beginning December 15, 2013 if our common stock trading price exceeds $32.45 per share for 20 of 30 consecutive trading days.

Note 11 — Supplemental Cash Flow Information

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

     
  Year Ended June 30,
     2014   2013   2012
Cash paid for interest   $ 139,575     $ 99,377     $ 103,346  
Cash paid for income taxes     3,641       12,873        

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

     
  Year Ended June 30,
     2014   2013   2012
Financing of insurance premiums   $ 21,967     $ 22,524     $ 22,211  
Preferred stock dividends                 (138 ) 
Derivative instruments premium financing     11,257       18,231       16,259  
Additions to property and equipment by recognizing asset retirement obligations     299,225       (9,820 )      (45,998 ) 
Repurchase of company common stock           13,997        
Treasury stock reissued for the EPL Acquisition     154,717              
Common stock issued for the EPL Acquisition     337,588              

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 2014, 2013 and 2012, we also awarded performance units. Of the total performance units awarded, 25% are time-based performance units (“Time-Based Performance Units”) and 75% are Total Shareholder Return Performance-Based Units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vest equally over a three-year period.

Time-Based Performance Units.  The amount due the employee at the vesting date is equal to the grant date unit value of $5.00 plus the appreciation in the stock price over the performance period, multiplied by the number of units that vest. For the fiscal year 2012 grant the initial stock price was $34.40 and for the fiscal year 2013 grant the initial stock price was $33.20 and for the fiscal year 2014 grant the initial stock price was $21.72.

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.

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Note 12 — Employee Benefit Plans  – (continued)

At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due employees will be settled 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 settled all vesting awards in cash. The July 21, 2014 vesting of the July 21, 2013 and 2012 Performance Unit awards were settled 50% in common stock and future vesting of the Performance Units may be settled 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,
     2014   2013   2012
Restricted Stock Units   $ 12,798     $ 10,707     $ 19,315  
Performance Units     11,446       10,569       31,148  
Total compensation expense recognized   $ 24,244     $ 21,276     $ 50,463  

As of June 30, 2014, we have 1,394,175 unvested Restricted Stock Units and 6,780,358 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 are newly issued by us. During the years ended June 30, 2014, 2013 and 2012, we issued 148,519 shares, 213,763 shares and 305,401 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, 2014 to December 31, 2014. We use the Black-Scholes Model to determine fair value, which incorporates assumptions to value stock-based awards. The shares issuable under the Employee Stock Purchase Plan are included in calculating diluted earnings per share, if dilutive. As of June 30, 2014 there was no unrecognized compensation. The compensation expense recognized and shares issued under the Employee Stock Purchase Plan were as follows (in thousands, except for shares):

     
  Year Ended June 30,
     2014   2013   2012
Compensation expense   $ 866     $ 813     $ 729  
Shares issued     92,297       74,806       46,985  

Stock Options

In September 2008, our Board of Directors granted 300,000 stock options to certain officers of the Company. 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. We utilized the Black-Scholes model to determine the fair value of these stock options. As of June 30, 2014, 100,000 of the vested options have been exercised and the remaining 200,000 vested options have not been exercised.

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Note 12 — Employee Benefit Plans  – (continued)

Defined Contribution Plans

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

     
  Year Ended June 30,
     2014   2013   2012
Profit Sharing Plan   $ 4,833     $ 2,738     $ 3,014  
401(k) Plan     3,395       3,381       3,195  
Total contributions   $ 8,228     $ 6,119     $ 6,209  

Note 13 — Related Party Transactions

We have a 20% interest in EXXI M21K and account for this investment using the equity method. 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 the LLOG Exploration acquisition, we guaranteed payment of asset retirement obligations by M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchase, we guaranteed payment of asset retirement obligation by M21K estimated at $18.6 million. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the year ended June 30, 2014 and 2013, we have received $3.1 million and $1.9 million, respectively, related to such guarantees.

Prior to the LLOG Exploration acquisition, EGC received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations. In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced. However, after the Eugene Island 330 and South Marsh Island 128 properties purchase on April 1, 2014, this fee was reduced to $0.98 per BOE produced. For the year ended June 30, 2014 and 2013, EGC received management fees of $3.8 million and $1.7 million, respectively.

On April 1, 2014 we closed on sale of certain oil and gas properties to M21K and on June 3, 2014, Energy XXI GOM, LLC, (“EXXI GOM”) our wholly owned indirect subsidiary closed on the sale of its 100% interests in South Pass 49 field to EPL, which is our wholly owned indirect subsidiary. See Note 3 —  Acquisitions and Dispositions of Notes to Consolidated Financial Statements in this Form 10-K.

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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,
     2014   2013   2012
Net income   $ 59,111     $ 162,081     $ 335,827  
Preferred stock dividends     11,489       11,496       13,028  
Induced conversion of preferred stock                 6,068  
Net income available for common stockholders   $ 47,622     $ 150,585     $ 316,731  
Weighted average shares outstanding for basic EPS     74,375       79,063       77,310  
Add dilutive securities     70       8,200       9,898  
Weighted average shares outstanding for diluted EPS     74,445       87,263       87,208  
Earnings per share
                          
Basic   $ 0.64     $ 1.90     $ 4.10  
Diluted   $ 0.64     $ 1.86     $ 3.85  

For the years ended June 30, 2014, 2013 and 2012, we had 8,336,700, 5,474 and 4,821, 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.

Litigation Related to the Merger

In March and April, 2014, three alleged EPL stockholders (the “plaintiffs”) filed three separate class action lawsuits in the Court of Chancery of the State of Delaware on behalf of EPL stockholders against EPL, its directors, Energy XXI, Energy XXI Gulf Coast, Inc., a Delaware corporation and an indirect wholly owned subsidiary of Energy XXI (“OpCo”), and Clyde Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of OpCo (“Merger Sub” and collectively, the “defendants”). The Court of Chancery of the State of Delaware consolidated these lawsuits on May 5, 2014. The consolidated lawsuit is styled In re EPL Oil & Gas Inc. Shareholders Litigation, C.A. No. 9460-VCN, in the Court of Chancery of the State of Delaware (the “lawsuit”).

Plaintiffs allege a variety of causes of action challenging the Agreement and Plan of Merger between Energy XXI, OpCo, Merger Sub, and EPL (the “merger agreement”), which provides for the acquisition of EPL by Energy XXI. Plaintiffs allege that (a) EPL’s directors have allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL have allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs’ causes of action are based on their allegations that (i) the merger allegedly provided inadequate consideration to EPL stockholders for their shares of EPL common stock; (ii) the merger agreement contains contractual terms — including, among others, the (A) “no solicitation,” (B) “competing proposal,” and (C) “termination fee” provisions — that allegedly dissuaded other potential acquirers from making competing offers for shares of EPL common stock; (iii) certain of EPL’s officers and directors allegedly received benefits — including (A) an offer for one of EPL’s directors to join the Energy XXI board of directors and (B) the triggering of change-in-control provisions in notes held by EPL’s executive officers — that were not equally shared by EPL’s stockholders; (iv) Energy XXI required

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Note 15 — Commitments and Contingencies  – (continued)

EPL’s officers and directors to agree to vote their shares of EPL common stock in favor of the merger; and (v) EPL provided, and Energy XXI obtained, non-public information that allegedly allowed Energy XXI to acquire EPL for inadequate consideration. Plaintiffs also allege that the Registration Statement filed on Form S-4 by EPL and Energy XXI on April 1, 2014 omits information concerning, among other things, (i) the events leading up to the merger, (ii) EPL’s efforts to attract offers from other potential acquirors, (iii) EPL’s evaluation of the merger; (iv) negotiations between EPL and Energy XXI, and (v) the analysis of EPL’s financial advisor. Based on these allegations, plaintiffs seek to have the merger agreement rescinded. Plaintiffs also seek damages and attorneys’ fees.

Defendants date to answer, move to dismiss, or otherwise respond to the lawsuit has been indefinitely extended. Neither Energy XXI nor EPL can predict the outcome of the lawsuit or any others that might be filed subsequent to the date of the filing of this quarterly report; nor can either Energy XXI or EPL predict the amount of time and expense that will be required to resolve the lawsuit. The defendants intend to vigorously defend the lawsuit.

Lease Commitments.  We have non-cancelable operating leases for office space and others that expire through December 31, 2022. Future minimum lease commitments as of June 30, 2014 under the operating leases are as follows (in thousands):

 
Year Ending June 30,  
2015   $ 4,163  
2016     4,717  
2017     5,012  
2018     4,176  
2019     4,276  
Thereafter     13,966  
Total   $ 36,310  

Rent expense, including rent incurred on short-term leases, for the years ended June 30, 2014, 2013 and 2012 was approximately $3,658,000, $2,777,000 and $2,493,000, respectively.

Letters of Credit and Performance Bonds.  We had $225.7 million in letters of credit and $170.5 million of performance bonds outstanding as of June 30, 2014.

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 guarantees related to the payment of asset retirement obligations and other liabilities by M21K for the EP Energy, LLOG Exploration and Eugene Island 330 and South Marsh Island 128 properties acquisitions. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. 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, 2014, we have entered into nine drilling rig commitments:

1) April 10, 2014 to October 27, 2014 at $54,448 per day.
2) January 1, 2014 to July 15, 2014 at $107,500 per day.
3) October 1, 2013 to September 1, 2014 at $125,000 per day.

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Note 15 — Commitments and Contingencies  – (continued)

4) March 10, 2014 to March 9, 2015 at $53,175 per day.
5) September 1, 2013 to August 31, 2014 at $140,000 per day.
6) February 15, 2014 to August 15, 2014 at $111,380 per day.
7) April 11, 2014 to September 15, 2014 at $112,000 per day.
8) July 1, 2014 to September 1, 2014 at $107,500 per day.
9) September 1, 2014 to October 1, 2014 at $107,500 per day.

At June 30, 2014, future minimum commitments under these contracts totaled $61.9 million.

Note 16 — Income Taxes

Our parent Company is a Bermuda company and it is 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, 2014, 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,
     2014   2013   2012
     (In Thousands)
U.S. income   $ 106,970     $ 223,337     $ 346,887  
Non-U.S. income     9,230       25,377       27,586  
Income before income taxes   $ 116,200     $ 248,714     $ 374,473  

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Note 16 — Income Taxes  – (continued)

The components of our income tax provision are as follows:

     
  Year Ended June 30,
     2014   2013   2012
     (In Thousands)
Current
                          
United States   $ 3,641     $ 12,872     $  
Non U.S.                  
State                 (53 ) 
Total current     3,641       12,872       (53 ) 
Deferred
                          
United States     53,448       76,222       38,699  
State           (2,461 )       
Total deferred     53,448       73,761       38,699  
Total income tax provision   $ 57,089     $ 86,633     $ 38,646  

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

     
  Year Ended June 30,
     2014   2013   2012
     (In Thousands)
Income before income taxes   $ 116,200     $ 248,714     $ 374,473  
Statutory rate     35 %      35 %      35 % 
Income tax expense computed at statutory rate     40,670       87,050       131,066  
Reconciling items
                          
Federal withholding obligation     10,343       10,343       10,371  
Nontaxable foreign income     (2,133 )      (8,214 )      (9,655 ) 
Change in valuation allowance           (59,853 )      (26,996 ) 
Tax return to provision adjustment to oil and natural gas properties           52,072        
Release prior abandonment loss reserve                 (7,106 ) 
Debt cancellation – bond repurchase                 (52,583 ) 
State income taxes (benefit), net of federal tax benefit           (2,461 )      (9,547 ) 
Non-deductible executive compensation     2,725       5,616       7,400  
Non-deductible transaction costs     1,853              
Other – Net     3,631       2,080       (4,304 ) 
Tax provision   $ 57,089     $ 86,633     $ 38,646  

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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,
     2014   2013
     (In Thousands)
Deferred tax assets – current
                 
Asset retirement obligation   $ 44,182     $  
Other     8,405        
Total deferred tax assets – current     52,587        
Deferred tax liabilities – current
                 
Federal withholding obligation           (20,517 ) 
Deferred tax assets – non current
                 
Asset retirement obligation     61,412       100,697  
Tax loss carryforwards on U.S. operations     448,404       386,899  
Accrued interest expense     79,636       65,418  
Deferred interest expense under IRC Sec. 162(j)           28,721  
Employee benefit plans           6,213  
Deferred state taxes     22,494       22,494  
Derivative instruments and other     12,163        
Other     11,471       6,860  
Total deferred tax assets – non current     635,580       617,302  
Deferred tax liabilities
                 
Derivative instruments and other           (10,193 ) 
Oil, natural gas properties and other property and equipment     (1,183,864 )      (628,554 ) 
Federal withholding obligation     (63,143 )      (34,983 ) 
Cancellation of debt     (9,680 )      (9,680 ) 
Employee benefit plans     (3,611 )       
Tax partnership activity     (53,826 )      (52,202 ) 
Total deferred tax liabilities – non current     (1,314,124 )      (735,612 ) 
Valuation allowance     (22,494 )      (22,494 ) 
Net deferred tax liability   $ (648,451 )    $ (161,321 ) 
Reflected in the accompanying balance sheet as
                 
Current deferred tax asset (liability)   $ 52,587     $ (20,517 ) 
Non-current deferred tax liability   $ (701,038 )    $ (140,804 ) 

The total change in deferred tax assets and liabilities in the year ended June 30, 2014 reflects a $25.3 million decrease in the deferred tax liability related to items recorded in other comprehensive income. This decrease resulted in a deferred tax asset at June 30, 2014 of $7.7 million related to other comprehensive income which is included in the derivative instruments line. The Company recorded $459 million in net deferred tax liabilities in conjunction with the EPL acquisition.

At June 30, 2014, we have a U.S. federal tax loss carryforward (“NOLs”) of approximately $1.3 billion, a state income tax loss carryforward of approximately $743 million, including amounts carried into the Company’s U.S. group from the EPL acquisition. The regular U.S. federal income tax NOLs will expire in various amounts beginning in 2026 and ending in 2034.

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Note 16 — Income Taxes  – (continued)

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 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. EPL similarly experienced an ownership change in 2009 and upon its acquisition in 2014. 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 have not recorded any reserves for uncertain tax positions. We have a gross unrecorded noncurrent deferred tax asset of $13.2 million representing a percentage depletion carryover resulting from the EPL acquisition.

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 2013. The tax years ended June 30, 2011 through 2014 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. On May 13, 2014, the U.S. Internal Revenue Service (“IRS”) notified the Company of their intent to examine the Company’s U.S. federal income tax return (Form 1120) for the year ended June 30, 2013. The resolution of unagreed tax issues cannot be predicted with absolute certainty, and differences between what has been recorded and the eventual outcomes may occur. The Company believes that it has adequately provided for income taxes and any related interest and penalties for all open tax years.

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 2015 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 $3.6 million cash in U.S. 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

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Note 17 — Concentrations of Credit Risk  – (continued)

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 45%, 35% and 32% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 43%, 37% and 37% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. J.P. Morgan Ventures Energy Corporation 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 or ExxonMobil curtailed their purchases.

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

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

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.

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

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

Level 1 — quoted prices in active markets for identical assets or liabilities.
Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).
Level 3 — unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

During fiscal year 2014, 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,
     2014   2013   2014   2013
Assets:
                                   
Oil and natural gas derivatives               $ 26,975     $ 96,455  
Liabilities:
                                   
Oil and natural gas derivatives                     $ 58,778     $ 36,180  
Restricted stock units   $ 9,425     $ 7,642                    
Time-based performance units     3,698       3,059                    
Total liabilities   $ 13,123     $ 10,701     $ 58,778     $ 36,180  

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

   
  Level 3
     Year Ended June 30,
     2014   2013
Liabilities:
                 
Performance-based performance units
                 
Balance at beginning of year   $ 6,778     $ 22,855  
Vested     (7,188 )      (23,161 ) 
Grants charged to income     7,320       7,084  
Balance at end of year   $ 6,910     $ 6,778  

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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,
     2014   2013
Prepaid expenses and other current assets
                 
Advances to joint interest partners   $ 10,336     $ 13,936  
Insurance     37,088       31,258  
Inventory     7,020       4,094  
Royalty deposit     12,262       1,210  
Other     5,824       240  
Total prepaid expenses and other current assets   $ 72,530     $ 50,738  
Accrued liabilities
                 
Advances from joint interest partners   $ 2,667     $ 1,348  
Employee benefits and payroll     43,480       30,730  
Interest payable     26,490       5,733  
Accrued hedge payable     7,874       2,214  
Undistributed oil and gas proceeds     34,473       47,766  
Severance taxes payable     8,014       922  
Repurchase of company common stock           13,997  
Other     10,528       2,482  
Total accrued liabilities   $ 133,526     $ 105,192  

Note 20 — Subsequent Events

On July 16, 2014, 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 12, 2014 to shareholders of record on August 29, 2014.

Note 21 — Selected Quarterly Financial Data — Unaudited

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

       
  Year Ended June 30, 2014
     Fourth
Quarter
  Third
Quarter
  Second
Quarter
  First
Quarter
Revenues   $ 324,134     $ 285,183     $ 296,816     $ 324,592  
Operating income     54,677       64,801       61,502       99,431  
Net income (loss)   $ (1,815 )    $ 7,292     $ 10,495     $ 43,139  
Preferred stock dividends     2,872       2,872       2,872       2,873  
Net income (loss) available for common stockholders   $ (4,687 )    $ 4,420     $ 7,623     $ 40,266  
Net income (loss) per share attributable to common stockholders(1)
                                   
Basic   $ (0.06 )    $ 0.06     $ 0.10     $ 0.53  
Diluted     (0.06 )      0.06       0.10       0.51  

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

       
  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  

(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,
     2014   2013   2012
     (In Thousands)
Property acquisitions
                          
Proved   $ 2,046,879     $ 108,825     $ 6,401  
Unevaluated     924,882       52,339        
Exploration costs     153,136       168,512       183,397  
Development costs     632,262       633,868       327,360  

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 unevaluated property costs and major development projects (in thousands):

         
  Net Costs Incurred During the Years Ended June 30,   Balance as of
June 30, 2014
     2011 and prior   2012   2013   2014
Unevaluated Properties (acquisition costs)   $ 38,289     $     $ 51,435     $ 890,696     $ 980,420  
Wells in Progress (exploratory costs)     122,724       89,611       120,492       (147,546 )      185,281  
     $ 161,013     $ 89,611     $ 171,927     $ 743,150     $ 1,165,701  

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

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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 natural 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:

     
  Oil
(MBbls)
  Natural Gas
(MMcf)
  Total
(MBOE)
Proved reserves at June 30, 2011     77,206       236,316       116,592  
Production     (11,172 )      (29,824 )      (16,143 ) 
Extensions and discoveries     11,444       27,821       16,081  
Revisions of previous estimates     9,098       (23,281 )      5,217  
Reclassification of proved undeveloped     (1,783 )      (2,042 )      (2,123 ) 
Proved reserves at June 30, 2012     84,793       208,990       119,624  
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  
Production     (10,978 )      (32,754 )      (16,437 ) 
Extensions and discoveries     17,141       19,703       20,424  
Revisions of previous estimates     (3,567 )      (29,822 )      (8,537 ) 
Sales of reserves     (4,159 )      (3,378 )      (4,722 ) 
Purchases of reserves     53,305       141,986       76,970  
Proved reserves at June 30, 2014     185,389       364,856       246,198  
Proved developed reserves
                          
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  
June 30, 2014     112,789       222,916       149,942  
Proved undeveloped reserves
                          
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  
June 30, 2014     72,600       141,940       96,256  

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Our proved developed reserve estimates increased by 40.4 MMBOE or 37% to 149.9 MMBOE at June 30, 2014 from 109.5 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 52.3 MMBOE, primarily in the EPL Acquisition.
Additions of 5.4 MMBOE from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from the 4 fields: West Delta 30, Main Pass 61, Main Pass 73 and Grand Isle 16.

Offset by:

Downward revision of 2.7 MMBOE, mainly due to lower than forecasted per well throughput at West Delta 73 and sanding issues at South Timbalier 54, offset by positive performance revisions at West Delta 30 and South Pass 49.
Divestiture of 4.7 MMBOE, and
Production of 16.4 MMBOE.

Our proved undeveloped reserve estimates increased by 27.3 MMBOE or 40% to 96.3 MMBOE at June 30, 2014 from 69.0 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 24.6 MMBOE, primarily in the EPL Acquisition.
Additions of 15.1 MMBOE, primarily additional drilling locations to make up for the lower throughput per well in West Delta 73, replacement locations for South Timbalier 54 and from identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 61.

Offset by

Downward revision of 5.9 MMBOE, primarily due to lease expiration in South Fresh Water Bayou, reallocation of reserves due to new information from the drilling program in Main Pass 61, and change of fluid type due to new information from the drilling program in West Delta 30.
Conversion of 6.6 MMBOE from proved undeveloped to proved developed reserves.

In the fiscal year ended June 30, 2014, we developed approximately 9.5% of our PUD reserves included in our June 30, 2013 reserve report, consisting of 18 gross, 18 net wells at a net cost of approximately $160.9 million. In addition, we also spent $101.7 million in developing PUD reserves that were still in progress at the end of the fiscal year ended June 30, 2014.

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 newly acquired proved undeveloped reserves. As scheduled in our long range plan, all of our proved undeveloped locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our report, with the exception of two. They are locations to be sidetracked from existing wellbores which are still producing economically thus cannot be drilled until the proved developed producing zones deplete.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows as of June 30, 2014 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $96.75 per barrel of oil (calculated using the unweighted average first-day-of-the-month West Texas Intermediate posted prices during the

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

12-month period ending on June 30, 2014). 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 $103.80 per barrel of oil and $42.10 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. The $103.80 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $96.75 per barrel (differential of $7.05 per barrel).

For natural gas, the average Henry Hub price used was $4.10 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 natural gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $4.14 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 natural gas reserves as of June 30, 2014, 2013 and 2012 are as follows (in thousands):

     
  June 30,
     2014   2013   2012
Future cash inflows   $ 20,162,506     $ 15,048,978     $ 10,009,119  
Less related future
                          
Production costs     5,500,669       3,657,595       2,737,969  
Development and abandonment costs     2,959,994       1,838,159       1,304,007  
Income taxes     2,546,155       2,591,351       1,377,363  
Future net cash flows     9,155,688       6,961,873       4,589,780  
Ten percent annual discount for estimated timing of cash flows     3,208,163       2,480,351       1,284,291  
Standardized measure of discounted future net cash flows   $ 5,947,525     $ 4,481,522     $ 3,305,489  

Changes in Standardized Measure of Discounted Future Net Cash Flows

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

     
  Year Ended June 30,
     2014   2013   2012
Beginning of year   $ 4,481,522     $ 3,305,489     $ 2,561,393  
Revisions of previous estimates
                          
Changes in prices and costs     (196,159 )      (106,002 )      855,382  
Changes in quantities     (389,570 )      635,562       153,537  
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs     533,133       1,598,548       604,266  
Purchases of reserves in place     1,735,957       480,111        
Accretion of discount     614,964       429,745       333,748  
Sales, net of production and gathering and transportation costs     (836,019 )      (842,268 )      (968,956 ) 
Net change in income taxes     14,134       (676,158 )      (215,873 ) 
Changes in rate of production     (253,290 )      (456,254 )      (13,438 ) 
Development costs incurred     247,865       125,925       24,519  
Changes in abandonment costs and other     (5,012 )      (13,176 )      (29,089 ) 
Net change     1,466,003       1,176,033       744,096  
End of year   $ 5,947,525     $ 4,481,522     $ 3,305,489  

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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 66 and is incorporated herein by reference.

Changes in Internal Control over Financial Reporting

Since the acquisition of EPL on June 3, 2014, the Company has been aligning EPL’s controls to the Company’s existing control environment. As this process was ongoing as of June 30, 2014, it was not possible for the Company to perform an assessment of EPL’s internal control over financial reporting as of June 30, 2014. Management expects that EPL’s controls will be aligned and integrated into the Company’s control environment within one year of the date of the acquisition and will include EPL in its assessment of the effectiveness of internal control over financial reporting as of June 30, 2015. EPL is our wholly-owned indirect subsidiary whose total assets and total revenues represent 47% and 5%, respectively, of the related consolidated financial statements amounts as of and for the year ended June 30, 2014.

Other than the change noted above, 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, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

On August 22, 2014, EGC, EPL, the lenders thereunder and the other parties thereto entered into the Waiver to the First Lien Credit Agreement, dated as of August 22, 2014 (the “Waiver”).

Based upon preliminary calculations, EGC determined it may have exceeded the total leverage ratio covenant and therefore EGC sought a temporary increase in the total leverage ratio covenant. EGC’s total leverage ratio covenant included within Section 7.2.4(a) of the First Lien Credit Agreement requires EGC to maintain a Total Leverage Ratio (as defined therein) of not more than 3.5 to 1.0 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC’s leverage ratio was estimated to be 3.6 to 1.0 for the quarter ended June 30, 2014. EGC received a waiver from the lenders under the First Lien Credit Agreement on August 22, 2014 with respect to this potential violation for the quarters ending June 30, 2014 and September 30, 2014. The waiver is conditioned upon EGC maintaining a Total Leverage Ratio of not more than 4.25 to 1.00 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC was in compliance with the requirements under the waiver for the fiscal quarter ended June 30, 2014 and expects to be in compliance therewith for the fiscal quarter ended September 30, 2014. EGC is currently in discussions with the lenders under the First Lien Credit Agreement to amend certain of the financial covenants in order to ensure that EGC will be in compliance with the covenants for the remainder of the 2015 fiscal year. There is

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no assurance that EGC will reach agreement with its lenders on these amendments. In the event an amendment cannot be obtained, EGC believes that it will be able to comply with the current covenants under the First Lien Credit Agreement through June 30, 2015 by taking certain actions within EGC’s control.

The foregoing description of the Waiver is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the Waiver, which is filed as Exhibit 10.26 hereto and incorporated herein by reference.

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

(2) Financial Statement Schedules

The restricted net assets of consolidated subsidiaries exceed 25% of our consolidated net assets, accordingly below is the schedule of parent-only financial statements as prescribed by Rule 12-04 of Regulation S-X. All other schedules are omitted because they are either not applicable or required information is shown in the consolidated financial statements or notes thereto.

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

   
  June 30,
     2014   2013
ASSETS
                 
Current assets   $ 135,943     $ 1,569  
Intercompany receivable     102,489       95,627  
Equity investments     1,744,908       1,259,247  
Intercompany notes receivable     171,000       171,000  
Other assets and debt issuance costs, net of accumulated amortization     7,299        
Total Assets   $ 2,161,639     $ 1,527,443  
LIABILITIES AND STOCKHOLDERS’ EQUITY
                 
Current liabilities   $ 20,825     $ 17,537  
Long-term debt     342,986        
Stockholders’ equity     1,797,828       1,509,906  
Total Liabilities and Stockholders’ Equity   $ 2,161,639     $ 1,527,443  

 
 
See accompanying Notes to Condensed Financial Statements.

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

     
  Year Ended June 30,
     2014   2013   2012
Operating Expenses
                          
General and administrative expense   $ 7,380     $ 7,439     $ 6,990  
Operating Loss     7,380       7,439       6,990  
Other Income (Expense)
                          
Income from equity method investees     66,995       156,516       331,110  
Interest income     16,788       16,679       16,722  
Interest expense     (14,485 )             
Guarantee income     3,135       1,900        
Total Other Income     72,433       175,095       347,832  
Income Before Income Taxes     65,053       167,656       340,842  
Income Tax Expense     5,942       5,575       5,015  
Net Income   $ 59,111     $ 162,081     $ 335,827  

 
 
See accompanying Notes to Condensed Financial Statements.

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

     
  Year Ended June 30,
     2014   2013   2012
Cash Flows From Operating Activities
                          
Net income   $ 59,111     $ 162,081     $ 335,827  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                          
Stock-based compensation and deferred income tax expense     9,013       (3,793 )      16,717  
Amortization of debt issuance costs and other     7,219                    
Income from equity method investees     (66,995 )      (156,516 )      (331,110 ) 
Changes in operating assets and liabilities     (5,880 )      24,209       (24,622 ) 
Net Cash Provided by (Used in) Operating Activities     2,468       25,981       (3,188 ) 
Cash Flows from Investing Activities
                          
Change in equity method investments     (185,568 )      (4,010 )      (1,000 ) 
Net Cash Used in Investing Activities     (185,568 )      (4,010 )      (1,000 ) 
Cash Flows from Financing Activities
                          
Proceeds from the issuance of common and preferred stock, net of offering costs     3,994       7,021       9,839  
Repurchase of company common stock     (30,824 )             
Conversion of preferred stock to common stock                 (6,040 ) 
Dividends to shareholders     (46,169 )      (37,488 )      (18,682 ) 
Debt issuance costs     (9,585 )             
Discount on convertible debt allocated to additional paid-in capital     63,432              
Proceeds from long-term debt     336,568              
Other     53       _       212  
Net Cash Provided by (Used in) Financing Activities     317,469       (30,467 )      (14,671 ) 
Net Increase (Decrease) in Cash and Cash Equivalents     134,369       (8,496 )      (18,859 ) 
Cash and Cash Equivalents, beginning of year     1,334       9,830       28,689  
Cash and Cash Equivalents, end of year   $ 135,703     $ 1,334     $ 9,830  

 
 
See accompanying Notes to Condensed Financial Statements.

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONDENSED FINANCIAL STATEMENTS

Note 1 —  Basis of Presentation

These condensed parent only financial statements of Energy XXI (Bermuda) Limited (the “Company”) do not include all of the information and notes normally included with financial statements prepared in accordance with U.S. GAAP and therefore, should be read in conjunction with the consolidated financial statements and notes thereto of the Company, included in this Annual Report on Form 10-K. The Company’s investments in its wholly-owned subsidiaries are accounted for under the equity method.

Energy XXI Gulf Coast, Inc.’s (“EGC”) credit agreement restricts the ability of EGC to make any dividend or other distributions to the Company, subject to certain exceptions. As of June 30, 2014, the total restricted net assets were approximately $1.38 billion. Accordingly, these condensed parent only financial statements have been prepared pursuant to Rule 5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

Note 2 —  Notes Receivable

The Company has advanced $171 million under promissory notes to its wholly owned subsidiary, which bear a simple interest rate of 9.75% per annum. Interest on notes receivable amounted to approximately $16.7 million, $16.7 million and $16.7 million for the years ended June 30, 2014, June 30, 2013 and June 30, 2012, respectively.

Note 3 —  Long-Term Debt

On November 18, 2013, the Company sold $400 million face value of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). The Company incurred underwriting and direct offering costs of $7.6 million which have been capitalized and will be amortized over the life of the 3.0% Senior Convertible Notes The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the Company’s election, based on an initial conversion rate of 24.7523 shares of common stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common stock). The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.

For accounting purposes, the $400 million aggregate principal amount of 3% Senior Convertible Notes for which we received cash was recorded at fair market value by applying the implied straight debt rate of 6.75% to allocate the proceeds between the debt component and the convertible equity component of the 3% Senior Convertible Notes. Based on applying the implied straight debt rate, the $400 million aggregate principal amount of the 3% Senior Convertible Notes was recorded at $336.6 million and the $63.4 million original issue discount will be amortized as an increase in interest expense over the life of the 3% Senior Convertible Notes.

Note 4 —  Stockholders’ Equity

On August 1, 2007, the Company’s common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, the Company’s common stock was admitted for trading on The NASDAQ Global Select Market (“NASDAQ”). The Company’s common stock trades on the NASDAQ and on the Alternative Investment Market of the London Stock Exchange (“AIM”) under the symbol “EXXI.” The Company’s shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. The Company has 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, and paid quarterly cash dividends of $0.12 per share to holders of our

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONDENSED FINANCIAL STATEMENTS

Note 4 —  Stockholders’ Equity  – (continued)

common stock on June 14, 2013, September 13, 2013, December 13, 2013, March 14, 2014 and June 13, 2014, to shareholders of record on May 31, 2013, August 30, 2013, November 29, 2013, February 28, 2014 and May 30, 2014, respectively.

Pursuant to the stock repurchase program approved by our Board of Directors in May 2013, during the year ended June 30, 2014, we incurred $94.2 million to repurchase 3,700,463 shares of our common stock at a weighted average price per share, excluding fees, of $25.45 and 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. As of June 30, 2014, $83.2 million remains available for repurchase under the share repurchase program.

In addition, concurrently with the offering of our 3.0% Senior Convertible Notes in November 2013, one of the Company’s wholly-owned subsidiary repurchased 2,776,200 shares of the Company’s common stock for approximately $76 million, at a weighted average price per share, excluding fees of $27.39.

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.

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.

Conversion of Preferred Stock

During the year ended June 30, 2014, we canceled and converted a total of 428 shares of our 5.625% Preferred Stock into a total of 4,288 shares of common stock using a conversion rate ranging from 10.0147 to 10.0579 common shares per preferred share and 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.

The 5.625% preferred stock is callable beginning December 15, 2013 if our common stock trading price exceeds $32.45 per share for 20 of 30 consecutive trading days.

Note 5 —  Guarantee

The Company has provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K for the EP Energy, LLOG Exploration and Eugene Island 330 and South Marsh Island 128 properties acquisitions. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the year ended June 30, 2014 and 2013, we have received $3.1 million and $1.9 million, respectively, related to such guarantees.

Note 6 —  Income Taxes

The Company is incorporated in Bermuda and is generally not subject to income tax in Bermuda. The Company operates through its various subsidiaries in the United States; accordingly income taxes have been provided based upon U.S. tax laws and rates as they apply to the Company’s current ownership structure. The Company is subject to 30% U.S. withholding taxes on payments made to it for interest on indebtedness and guarantee provided.

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONDENSED FINANCIAL STATEMENTS

Note 7 — Supplemental Cash Flow Information

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

     
  Year Ended June 30,
     2014   2013   2012
Cash paid for interest   $ 6,767     $     $  

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

     
  Year Ended June 30,
     2014   2013   2012
Common stock issued for the EPL Acquisition, net   $ 315,394     $     $  

Note 8 —  Subsequent Events

On July 16, 2014, 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 12, 2014 to shareholders of record on August 29, 2014.

(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 25th day of August 2014.

ENERGY XXI (BERMUDA) LIMITED

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

John D. Schiller, Jr.
Chairman of the Board, President 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, President and
Chief Executive Officer
(Principal Executive Officer)
  August 25, 2014
/s/ DAVID WEST GRIFFIN

David West Griffin
  Chief Financial Officer and
(Principal Financial Officer and
Principal Accounting Officer)
  August 25, 2014
/s/ WILLIAM COLVIN

William Colvin
  Director   August 25, 2014
/s/ PAUL DAVISON

Paul Davison
  Director   August 25, 2014
/s/ CORNELIUS DUPRÉ II

Cornelius Dupré II
  Director   August 25, 2014
/s/ HILL A. FEINBERG

Hill A Feinberg
  Director   August 25, 2014
/s/ KEVIN S. FLANNERY

Kevin S. Flannery
  Director   August 25, 2014
/s/ SCOTT A. GRIFFITHS

Scott A. Griffiths
  Director   August 25, 2014

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EXHIBIT INDEX

     
Exhibit
Number
  Description   Originally Filed as Exhibit   File Number
2.1   Agreement and Plan of Merger among Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., Clyde Merger Sub, Inc. and EPL Oil & Gas, Inc., dated as of March 12, 2014   Included as Annex A to the
Registration Statement on Form S-4
filed on April 1, 2014
  333-194942
2.2   Amendment No. 1 to Agreement and Plan of Merger among Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., Clyde Merger Sub, Inc. and EPL Oil & Gas, Inc., dated as of April 15, 2014   2.2 to Energy XXI (Bermuda)
Limited’s Form S-4/A filed on
April 15, 2014
  333-194942
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 related to the 9.25% Senior Notes due 2017, 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 related to the 7.75% Senior Notes due 2019, dated as of February 25, 2011 among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee   4.1 to Form 8-K filed on February 28,
2011
  001-33628
4.5   Indenture related to the 7.50% Senior Notes due 2021, dated as of September 26, 2013 among Energy XXI Gulf Coast, Inc., Energy XXI (Bermuda) Limited, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee   4.1 to the Company’s Form 8-K filed on September 26, 2013   001-33628
4.6   Registration Rights Agreement dated as of September 26, 2013 among Energy XXI Gulf Coast, Inc., Citigroup Global Markets Inc. and RBS Securities Inc., as representatives of the Initial Purchasers, Energy XXI (Bermuda) Limited and the Guarantors named therein   4.2 to the Company’s Form 8-K filed
on September 26, 2013
  001-33628

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Exhibit
Number
  Description   Originally Filed as Exhibit   File Number
4.7    Indenture related to the 3.0% Senior Convertible Notes due 2018, dated November 22, 2013, by and between Energy XXI (Bermuda) Limited and Wells Fargo Bank, National Association, as trustee (including the form of 3.0% Senior Convertible Note due 2018)   4.1 to the Company’s Form 8-K filed
on November 22, 2013
  001-33628
4.8    Indenture related to the 6.875% Senior Notes due 2024, dated as of May 27, 2014, by and among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee   4.1 to the Company’s Form 8-K filed
on May 29, 2014
  001-33628
4.9    Registration Rights Agreement dated as of May 27, 2014 among Energy XXI Gulf Coast, Inc., Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as representatives of the Initial Purchasers and the Guarantors named therein   4.2 to the Company’s Form 8-K filed
on May 29, 2014
  001-33628
4.10   Indenture related to the 8.25% Senior Notes due 2018, dated as of February 14, 2011, by and among Energy Partners, Ltd., as Issuer, the Guarantors named therein and U.S. Bank National Association, as Trustee   4.1 to EPL Oil & Gas, Inc. Form 8-K
filed on February 15, 2011
  001-16179
4.11   Supplemental Indenture related to the 8.25% Senior Notes due 2018, dated as of March 14, 2011, by and among Anglo-Suisse Offshore Pipeline Partners, LLC, as a Guarantor, Energy Partners, Ltd., as Issuer, the other Guarantors named therein and U.S. Bank National Association, as Trustee   4.2 to EPL Oil & Gas, Inc. Form S-4
filed on August 14, 2011
  333-175567
4.12   Second Supplemental Indenture related to the 8.25% Senior Notes due 2018, dated October 31, 2012, by and among Hilcorp Energy GOM, LLC, as a Guarantor, EPL Oil & Gas, Inc., as Issuer, the other Guarantors named therein, and U.S. Bank National Association, as Trustee   4.3 to EPL Oil & Gas, Inc.
Form 10-K filed on March 7, 2013
  001-16179
4.13   Indenture related to the 8.25% Senior Notes due 2018, dated October 25, 2012, by and among EPL Oil & Gas, Inc., the Guarantors named therein and U.S. Bank National Association, as Trustee   4.1 to EPL Oil & Gas, Inc. Form 8-K
filed on October 30, 2012
  001-16179

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Exhibit
Number
  Description   Originally Filed as Exhibit   File Number
4.14   First Supplemental Indenture related to the 8.25% Senior Notes due 2018, dated October 31, 2012, by and among Hilcorp Energy GOM, LLC, as a Guarantor, EPL Oil & Gas, Inc., as Issuer, the other Guarantors named therein, and U.S. Bank National Association, as Trustee   4.5 to EPL Oil & Gas, Inc.
Form 10-K filed on March 7, 2013
  001-16179
4.15   Third Supplemental Indenture related to the 8.25% Senior Notes due 2018, by and among EPL Oil & Gas, Inc., the other Guarantors named therein and U.S. Bank National Association, as Trustee, dated April 18, 2014   4.1 to EPL Oil & Gas, Inc. Form 8-K
filed on April 21, 2014
  001-16179
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
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

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Exhibit
Number
  Description   Originally Filed as Exhibit   File Number
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 1, 2014)          
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
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     Sixth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of September 27, 2013   10.1 to the Company’s Form 8-K filed
on September 27, 2013
  001-33628
10.24     Seventh Amendment to Second Amended and Restated First Lien Credit Agreement dated as of April 7, 2014   10.1 to the Company’s Form 8-K filed
on April 7, 2014
  001-33628
10.25*    Eighth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 23, 2014          
10.26*    Waiver to Second Amended and Restated First Lien Credit Agreement, dated as of August 22, 2014       

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Exhibit
Number
  Description   Originally Filed as Exhibit   File Number
10.27     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
10.28   Purchase Agreement, dated September 23, 2013, by and between Energy XXI Gulf Coast, Inc., Citigroup Global Markets Inc. and RBS Securities Inc., as representatives of the Initial Purchasers, Energy XXI (Bermuda) Limited and the Guarantors named therein   10.1 to the Company’s Form 8-K filed on September 26, 2013   001-33628
10.29   Purchase Agreement, dated as of November 18, 2013, among Energy XXI (Bermuda) Limited, Barclays Capital Inc., Citigroup Global Markets Inc., Wells Fargo Securities, LLC and the other initial purchasers named therein.   10.1 to the Company’s Form 8-K filed on November 22, 2013   001-33628
10.30   Form of Energy XXI Voting Agreement, dated as of March 12, 2014   10.1 to the Company’s Form 8-K filed on March 13, 2013   001-33628
10.31   Form of EPL Oil & Gas Voting Agreement, dated as of March 12, 2014          
10.32   Consulting Agreement, dated as of April 15, 2014, by and between Energy XXI (Bermuda) Limited and Gary C. Hanna   10.28 to Amendment No. 1 to the Company’s Registration Statement on Form S-4 filed on April 15, 2014   333-194942
10.33   Consulting Agreement, dated as of April 15, 2014, by and between Energy XXI (Bermuda) Limited and T.J. Thom   10.29 to Amendment No. 1 to the Company’s Registration Statement on Form S-4 filed on April 15, 2014   333-194942
10.34   Purchase Agreement, dated May 12, 2014, by and between Energy XXI Gulf Coast, Inc., Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as representatives of the Initial Purchasers and the Guarantors named therein.   10.1 to the Company’s Form 8-K filed on May 15, 2014   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       

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Exhibit
Number
  Description   Originally Filed as Exhibit   File Number
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.

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