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, 2016

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 Ltd

(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 under Section 12(b) of the Act
Common Stock, par value $0.005 per share	Not Applicable

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 o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes x No o

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

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

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

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $77,007,124 based on the closing sale price of $1.01 per share as reported on The NASDAQ Global Select Market on December 31, 2015, 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 September 9, 2016 was 97,824,054.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2016 Annual Meeting of Shareholders, which will be filed within 120 days of June 30, 2016, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS		ii
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		1
PART I
Item 1 Business		3
Item 1A Risk Factors		24
Item 1B Unresolved Staff Comments		48
Item 2 Properties		48
Item 3 Legal Proceedings		48
Item 4 Mine Safety Disclosures		48
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		49
Item 6 Selected Financial Data		51
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations		54
Item 7A Quantitative and Qualitative Disclosures About Market Risk		86
Item 8 Financial Statements and Supplementary Data		88
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		168
Item 9A Controls and Procedures		168
Item 9B Other Information		169
PART III
Item 10 Directors, Executive Officers and Corporate Governance		169
Item 11 Executive Compensation		169
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		169
Item 13 Certain Relationships and Related Transactions, and Director Independence		170
Item 14 Principal Accountant Fees and Services		170
PART IV
Item 15 Exhibits and Financial Statement Schedules		170
Signatures		179

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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).

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 or a service well.

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.

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 fractional working interest owned 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 wells and related equipment and facilities.

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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 formations. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional pictures.

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 refers to 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. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to those summarized below:

• risks and uncertainties associated with the voluntary petitions for reorganization (the petitions collectively, the “Bankruptcy Petitions”) filed in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) seeking relief under the provisions of chapter 11 of Title 11 (“Chapter 11”) of the United States Bankruptcy Code (the “Bankruptcy Code”), including our inability to develop, confirm and consummate a plan under Chapter 11 or an alternative restructuring transaction, including a sale of all or substantially all of our assets, which may be necessary to continue as a going concern;

• inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;

• our ability to obtain the approval of the Bankruptcy Court with respect to motions or other requests made to the Bankruptcy Court in the Debtors’ (as defined below) Chapter 11 cases (the “Chapter 11 Cases”), including maintaining strategic control as debtor-in-possession;

• our ability to maintain sufficient liquidity and/or obtain adequate financing to allow us to execute our business plan post-emergence from Chapter 11;

• the effects of the Chapter 11 Cases on the Company and on the interests of various constituents, including holders of our common stock;

• Bankruptcy Court rulings in the Chapter 11 Cases as well as the outcome of all other pending litigation and the outcome of the Chapter 11 proceedings in general;

• the length of time that the Company will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings;

• risks associated with third party motions in the Chapter 11 Cases, which may interfere with our ability to confirm and consummate a plan of reorganization;

• the potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations;

• increased advisory costs to execute a reorganization;

• the impact of NASDAQ’s delisting of our common stock on the liquidity and market price of our common stock and on our ability to access the public capital markets;

• our business strategy;

• further or sustained declines in the prices we receive for our oil and natural gas production;

• our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;

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• our future financial condition, results of operations, revenues, expenses and cash flows;

• our future levels of indebtedness, liquidity, compliance with financial covenants and our ability to continue as a going concern;

• our inability to obtain additional financing necessary to fund our operations, capital expenditures, and to meet our other obligations;

• our ability to post additional collateral for current bonds or comply with any new regulations or Notices to Lessees and Operators (“NTLs”) imposed by the Bureau of Ocean Energy Management (the “BOEM”);

• economic slowdowns that can adversely affect consumption of oil and natural gas by businesses and consumers;

• uncertainties in estimating our oil and natural gas reserves and net present values of those reserves;

• the need to take ceiling test impairments due to lower commodity prices;

• hedging activities that expose us to pricing and counterparty risks;

• our ability to hedge future oil and natural gas production may be limited by lack of available counterparties and to the extent we are able to enter into hedging arrangements;

• replacing our oil and natural gas reserves;

• geographic concentration of our assets;

• uncertainties in exploring for and producing oil and natural gas, including exploitation, development, drilling and operating risks;

• our ability to make acquisitions and to integrate acquisitions;

• our ability to establish production on our acreage prior to the expiration of related leaseholds;

• availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;

• disruption of operations and damages due to capsizing, collisions, hurricanes or tropical storms;

• environmental risks;

• availability, cost and adequacy of insurance coverage;

• competition in the oil and natural gas industry;

• our inability to retain and attract key personnel;

• the effects of government regulation and permitting and other legal requirements; and

• costs associated with perfecting title for mineral rights in some of our properties.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read (1) Part I, Item 1A. “Risk Factors” and elsewhere in this Form 10-K, (2) our reports and registration statements filed from time to time with the SEC and (3) other public announcements we make from time to time.

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

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PART I

Item 1. Business

Overview

Energy XXI Ltd, including 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 natural gas reserves and related assets. With our principal operating subsidiary headquartered in Houston, Texas, we have historically 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”). We were listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “EXXI” prior to the suspension of our common stock from trading at the opening of business on April 25, 2016, in connection with the commencement of the Chapter 11 bankruptcy proceedings described below. Our common stock resumed trading on the OTC Markets Group Inc.’s OTC Pink (the “OTC Pink”) under the symbol “EXXIQ” on April 25, 2016. After the suspension period, our common stock was formally delisted from NASDAQ on May 19, 2016.

We have historically focused on 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.

Since our inception in 2005, we have completed six major acquisitions for aggregate cash consideration of approximately $5,000 million. In February 2006, we acquired Marlin Energy, L.L.C. 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. for approximately $312.5 million in cash. In June 2007, we purchased certain GoM Shelf properties from Pogo Producing Company (“Pogo”) for approximately $415.1 million. In November 2009, we acquired certain GoM Shelf oil and natural gas interests from MitEnergy Upstream LLC, a subsidiary of Mitsui & Co., Ltd., for total cash consideration of $276.2 million. 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 $1,010 million. On June 3, 2014, we completed the acquisition of EPL Oil & Gas, Inc. (“EPL”) for approximately $2,500 million, including the assumption of debt (the “EPL Acquisition”). The assets acquired in the EPL Acquisition are located on the GoM Shelf. Please see Note 4 — “Acquisitions and Dispositions” of Notes to our Consolidated Financial Statements in this Form 10-K for 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 742,197 net acres, ownership in 258 blocks, existing infrastructure to facilitate our growth and 16,766 square miles of 3D seismic data. We own and operate nine of the largest GoM Shelf oil fields ranked by total cumulative oil production to date and utilize various techniques to increase the recovery factor and thus increase the total oil recovered. The techniques utilized by us to date include:

• reviewing historical files to identify situations where partially depleted or overlooked reservoirs were determined to be uneconomic and abandoned in previous price environments;

• performing field studies, reservoir simulations and other analysis to identify previously overlooked, missed or under-appreciated opportunities to recover incremental oil reserves;

• 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;

• optimizing gas lift and other standard production techniques to optimize recovery from existing wellbores;

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• 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; and

• 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.

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 oil reservoirs when there are adequate funds in which to do so.

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.

At June 30, 2016, our total proved reserves were 86.6 MMBOE of which 77% were oil and 100% were classified as proved developed. Due to continued constraints on available capital, our proved reserve estimates do not include any proved undeveloped reserves as of June 30, 2016. Further, the reclassification of proved undeveloped reserves also had an impact on the proved developed reserves volumes as it shortened the economic life of fields and thereby reduced economic production from the proved developed reserves category.

We operated or had an interest in 635 gross producing wells on 452,083 net developed acres, including interests in 60 producing fields. We believe operating our assets is a key to our success and approximately 89% 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.

Bankruptcy Proceedings and Preceding Events

During the second quarter of fiscal year 2015, oil prices began a substantial and rapid decline with low prices continuing throughout fiscal year 2016. In response to that decline, we executed a series of financial and operational activities highlighted below:

• Our capital expenditures in fiscal year 2016 were reduced to $165 million, as compared to actual capital expenditures in fiscal year 2015 (excluding acquisition activity) of approximately $649 million. Our fiscal year 2016 budget was primarily focused on: (i) recompletion opportunities and lower risk development drilling opportunities in fields where we have had previous success and (ii) eliminating capital commitments on exploration and other activities that do not provide incremental production.

• We reduced field level operating costs, bringing the total amount of direct lease operating costs for fiscal year 2016 down by approximately 30% from the fiscal year 2015, and we are continuing to focus on operational and cost efficiencies.

• We suspended dividends on our common stock.

• During fiscal year 2015, we closed our private placement of $1,450 million in aggregate principal amount of our 11% Senior Secured Second Lien Notes due 2020 (the “Second Lien Notes”) for net proceeds of $1,355 million, after deducting the initial purchasers’ discount and direct offering costs paid by us. Of the net proceeds, $836 million was used to reduce our outstanding borrowings under our Second Amended and Restated First Lien Credit Agreement (as amended, the “First Lien Credit Agreement” or “Revolving Credit Facility”) to $150 million, with the remaining amount available for general corporate purposes, including funding a portion of our capital expenditure program for fiscal year 2015 and for fiscal year 2016 as well as funding a portion of our bond repurchases in fiscal year 2016.

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• In connection with the issuance of the Second Lien Notes, we proactively amended our Revolving Credit Facility, to, among other things, reduce the total borrowing base availability to $500 million and make certain modifications to the existing financial covenants. On November 30, 2015, the lenders under our Revolving Credit Facility (the “Lenders”) reaffirmed the total borrowing base of our Revolving Credit Facility at $500 million and temporarily relaxed the requirements of certain financial covenants. On February 29, 2016, the Thirteenth Amendment and Waiver to our Revolving Credit Facility (the “Thirteenth Amendment”) became effective and on March 14, 2016, the Fourteenth Amendment and Waiver to our Revolving Credit Facility (the “Fourteenth Amendment”) became effective, extending the term of the Thirteenth Amendment until April 15, 2016 and reducing the borrowing base to $327.2 million.

• On June 30, 2015, we sold the Grand Isle Gathering System (“GIGS”) for $245 million in cash, plus the assumption of an estimated $12.5 million asset retirement obligation associated with the decommissioning costs of the GIGS. In connection with the closing of the sale of the GIGS, we entered into a triple-net lease with Grand Isle Corridor, LP, a subsidiary of CorEnergy Infrastructure Trust, Inc., pursuant to which we continue to operate the GIGS.

• On June 30, 2015, we sold our interest in the East Bay field for cash consideration of $21 million, plus the assumption by the buyer of asset retirement obligations totaling approximately $55.1 million.

• During January 2015, we monetized our existing calendar 2015 ICE Brent three-way collars and Argus-LLS put spreads for total net proceeds of approximately $73.1 million. Additionally, we repositioned our calendar 2015 hedging portfolio by putting on Argus-LLS three-way collars, and we entered into NYMEX WTI collars to hedge a portion of our calendar 2016 production at the current commodity prices, which provided us some price protection against further decline in oil prices. In March 2016, pursuant to the Fourteenth Amendment we unwound all our outstanding hedging contracts for $50.6 million and used the proceeds therefrom to repay amounts of outstanding loans to EPL under the First Lien Credit Agreement.

• From July 1, 2015 through March 31, 2016, we acquired approximately $1,713.7 million of our unsecured notes in open market transactions at a total cost of approximately $215.9 million (excluding accrued interest) and recorded a gain totaling approximately $1,492.4 million, net of associated debt issuance costs and certain other expenses. These amounts include the $266.6 million purchase of EPL’s 8.25% Senior Notes due February 2018 (the “8.25% Senior Notes”) by Energy XXI Gulf Coast, Inc., an indirect wholly-owned subsidiary of Energy XXI Ltd (“EGC”) in open market transactions, which continue to be held by EGC, and the $471.1 million of EGC’s 9.25% Senior Notes due 2017 (the “9.25% Senior Notes”) repurchased by EGC in open market transactions, which continue to be held by EGC. In addition, certain bondholders holding $37 million in face value of our 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”) requested for conversion. Upon conversion, we recorded a gain of approximately $33.2 million after proportionate adjustment to the related debt issue costs, accrued interest and original debt issue discount. Post-debt repurchases and conversion, our total indebtedness owed to third parties was reduced to $2,863.5 million.

As a result of continued decreases in commodity prices and our substantial debt burden, we continued throughout fiscal 2016 to work with our financial and legal advisors to analyze a variety of solutions to reduce our overall financial leverage, while maintaining primary focus on preserving liquidity. As part of this process, we engaged in discussions with certain of our debtholders and other stakeholders to develop and implement a comprehensive plan to restructure our balance sheet. As part of these ongoing discussions, on February 16, 2016, we elected to enter into the 30-day grace period under the terms of the indenture governing EPL’s 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016.

On March 15, 2016, as part of our ongoing discussions with certain of our debtholders, we elected to make the deferred interest payment on the 8.25% Senior Notes, while electing not to make the interest payments due on the Second Lien Notes and on EGC’s 6.875% Senior Notes due 2024, commencing a new 30-day grace period. During the new 30-day grace period, we continued discussions with an ad hoc

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committee of certain holders of EGC’s Second Lien Notes (the “Second Lien Noteholders”) and a steering committee of the Lenders under our Revolving Credit Facility regarding a potential restructuring. On April 11, 2016, the Debtors entered into a Restructuring Support Agreement (as amended, the “Restructuring Support Agreement”) with certain Second Lien Noteholders, providing that the Second Lien Noteholders party thereto will support a restructuring of the Debtors, subject to the terms and conditions of the Restructuring Support Agreement. As contemplated in the Restructuring Support Agreement, the terms of the restructuring of the Debtors, are to be effectuated through a joint prearranged plan of reorganization. Pursuant to the Plan (as defined below), we expect to eliminate more than $2,800 million aggregate principal amount of debt and accrued interest held by/due to third-parties, substantial intercompany debt (including the $325 million intercompany note owed to EGC by EPL, the $266.6 million of the 8.25% Senior Notes purchased by EGC in open market transactions and potentially certain of the Debtors’ intercompany payable balances) as well as the $471.1 million of EGC’s 9.25% Senior Notes repurchased by EGC in open market transactions. As the Plan eliminates substantially all of our prepetition indebtedness other than indebtedness under our Revolving Credit Facility, it will result in a significantly deleveraged capital structure.

On April 14, 2016 (the “Petition Date”), Energy XXI Ltd, EGC, EPL, an indirect wholly-owned subsidiary of Energy XXI Ltd and certain other subsidiaries of Energy XXI Ltd as listed on Exhibit 21.1 of this Form 10-K (together with Energy XXI Ltd, the “Debtors”) (excluding Energy XXI GIGS Services, LLC, which leases a subsea pipeline gathering system located in the shallow GoM Shelf and storage and onshore processing facilities on Grand Isle, Louisiana, Energy XXI Insurance Limited through which certain insurance coverage for its operations is obtained by the Company, Energy XXI (US Holdings) Limited, Energy XXI International Limited, Energy XXI Malaysia Limited and Energy XXI M21K, LLC, (together, the “Non-Debtors”)) filed the Bankruptcy Petitions in the Bankruptcy Court seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. The Debtors’ Chapter 11 Cases are being jointly administered under the caption “In re: Energy XXI Ltd, et al., Case No. 16-31928.” The Debtors continue to operate their businesses and manage their assets as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Concurrently with the filing of the Bankruptcy Petitions and to streamline the business operations and organization structure following the emergence from Chapter 11 proceedings, Energy XXI Ltd filed a petition to commence an official dissolution under the laws of Bermuda before the Supreme Court of Bermuda (the “Bermuda Proceeding”). On April 15, 2016, John C. McKenna was appointed as provisional liquidator by the Supreme Court of Bermuda. The Bermuda Proceeding is a limited ancillary proceeding under which dissolution of Energy XXI Ltd will be completed following the confirmation of the bankruptcy plan by the Bankruptcy Court, accordingly, the Bankruptcy Court retains primary jurisdiction over Energy XXI Ltd during the Chapter 11 proceedings. On June 3, 2016, the Bermuda Court granted the Debtors’ request to adjourn the Bermuda Proceeding through November 4, 2016.

On April 26, 2016, the United States Trustee for the Southern District of Texas (the “U.S. Trustee”) appointed an official committee of unsecured creditors (the “UCC”). The UCC is currently composed of the following members: (a) Wilmington Trust, National Association, as successor indenture trustee with respect to certain unsecured notes issued by EGC; (b) Axip Energy Services, LP; (c) Fab-Con, Incorporated; (d) Petroleum Solutions International, LLC; (e) B&J Martin, Inc; (f) Wilmington Savings Fund Society, FSB, as successor indenture trustee with respect to the 3.0% Senior Convertible Notes; and (g) Delaware Trust Company, as successor indenture trustee with respect to EPL’s 8.25% Senior Notes.

On June 2, 2016, an ad hoc group of equity holders filed a motion seeking to appoint an official committee of equity holders pursuant to section 1102(a)(2) of the Bankruptcy Code (the “Equity Committee Motion”). The Equity Committee Motion was opposed by the Debtors, the UCC, certain Second Lien Noteholders and Wells Fargo Bank, N.A. as administrative agent (the “First Lien Agent”) under our Revolving Credit Facility, all of whom filed objections to the Equity Committee Motion. However, at an emergency hearing on the Equity Committee Motion on June 15, 2016, the Bankruptcy Court ruled that it would be appropriate to appoint an equity committee, subject to certain limitations. On June 17, 2016, the U.S. Trustee appointed an official committee of equity security holders (the “Equity Committee”).

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On July 15, 2016, the Bankruptcy Court entered the Order (A) Approving the Disclosure Statement and the Form and Manner of Service Related Thereto, (B) Setting Dates for the Objections Deadline and Hearing Related to Confirmation of the Plan, and (C) Granting Related Relief [Docket No. 805], approving the adequacy of the Third Amended Disclosure Statement for the Debtors’ Proposed Joint Chapter 11 Plan of Reorganization [Docket No. 809] (the “Disclosure Statement”) and related solicitation materials, thereby authorizing the Debtors to solicit votes to accept or reject the Debtors’ Proposed Joint Chapter 11 Plan of Reorganization [Docket No. 810] from applicable creditor constituencies.

On September 8, 2016, a meeting (the “September 8 Meeting”) occurred between certain representatives of the Debtors, certain Second Lien Noteholders, the UCC, certain holders of unsecured indebtedness issued by EGC (the “Ad Hoc EGC Group”) and certain holders of unsecured indebtedness issued by EPL (the “Ad Hoc EPL Group”), during which the Second Lien Noteholders made an offer to the Debtors, the UCC, the Ad Hoc EGC Group and advisors to the Ad Hoc EPL Group to modify certain terms of the Debtor’s July 15, 2016 proposed plan of reorganization (the “September 8 Second Lien Offer”). The UCC and the Ad Hoc EGC Group did not accept the September 8 Second Lien Offer, submit a counter-offer or enter into any negotiations with the Debtors or the Second Lien Noteholders following the receipt of the September 8 Second Lien Offer during the September 8 Meeting. However, on September 12, 2016, the Debtors received a proposal for an alternative chapter 11 plan of reorganization from the Ad Hoc EGC Group and the Ad Hoc EPL Group, which the Debtors are in the process of reviewing with their advisors.

Following subsequent negotiations between the Debtors and the Second Lien Noteholders, on September 13, 2016, the Debtors and the Second Lien Noteholders entered into the Fifth Amendment to the Restructuring Support Agreement (the “Fifth RSA Amendment”), which provided, among other things, that the Debtors file an amended plan of reorganization to reflect the terms of the Fifth RSA Amendment. The boards of directors of the Company, EGC and EPL, including all independent directors, approved the entry into the Fifth RSA Amendment and the term sheet attached thereto. Subject to approval by the Bankruptcy Court, the terms of the restructuring of the Debtors, as contemplated in the Fifth RSA Amendment, were included in the Debtors’ Amended Proposed Joint Chapter 11 Plan of Reorganization [Docket No. 1307], filed September 14, 2016 (as may be amended, modified, or supplemented from time to time, the “Plan”).

On September 16, 2016, the Debtors filed an initial form of supplement (the “DS Supplement”) to the Disclosure Statement, which summarized the modifications to the Plan contemplated by the Fifth RSA Amendment. The Plan, as now amended, supersedes the September 8 Second Lien Offer. The Debtors sought approval of the adequacy of the DS Supplement and related solicitation materials at a hearing held before the Bankruptcy Court on September 22, 2016, following which the Bankruptcy Court approved the DS Supplement in its Order (A) Approving the Adequacy of the Supplement to the Debtors’ Third Amended Disclosure Statement Setting Forth Modifications to the Debtors’ Proposed Joint Chapter 11 Plan of Reorganization and the Continued Solicitation of the Plan and (B) Granting Related Relief [Docket No. 1416] on September 25, 2016. The Debtors will distribute the DS Supplement and related solicitation materials to creditors entitled to vote on the Plan to enable such creditors to vote on the Plan changes.

In an effort to consensually resolve outstanding disputes among the parties in interest, representatives for the Debtors, the First Lien Agent, the Second Lien Noteholders, the UCC and its members, the Equity Committee, the Ad Hoc EGC Group, and the Ad Hoc EPL Group have agreed to participate in a confidential and non-binding mediation process, as discussed on the record at a hearing before the Bankruptcy Court on September 13, 2016. On September 16, 2016, the Bankruptcy Court appointed Judge Leif Clark as the mediator. Mediation is scheduled to commence on September 28, 2016.

The hearing to consider confirmation of the Plan is currently set for October 17, 2016, but may change depending upon the outcome of, among other things, mediation and other developments in the Chapter 11 Cases.

For more information on the reorganization process, the Plan and the recent events that have impacted us, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Events.”

7

Business Strategy and Strengths

We have historically focused on developing high quality oil-producing assets with low production decline rates. 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.

Due to 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 stakeholder 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 89% 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.

For the duration of our Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A, “Risk Factors.” Because of these risks and uncertainties, the description of our operations, properties and capital plans included in this Form 10-K may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

General Information on Properties

Below are descriptions of our significant properties at June 30, 2016. These properties represent our core properties and are ranked based on PV-10 (as defined below) of proved reserves as of June 30, 2016.

West Delta 73 Field.  We operate and have a 100% working interest in the West Delta 73 field, located 28 miles offshore of Grand Isle, Louisiana in approximately 175 feet of water on the Outer Continental Shelf (“OCS”). The field, which was first discovered in 1962 by Humble Oil and Refining, is a large low relief faulted anticline. The field produces from Pleistocene through Upper Miocene aged sands trapped structurally on the high side closures over the large anticlinal feature from 1,500 feet to 13,000 feet. The field has produced in excess of 388 MMBOE. There are seven production platforms and 48 active wells located throughout the field. The field’s net production for the month of June 2016 of 5.0 MBOE/Day (“MBOED”) accounted for approximately 11% of our net production. Net proved reserves for the field, which is our largest field based upon net proved reserves, were 90% oil at June 30, 2016.

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 63 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 27 producing wells and three major production platforms located throughout the field. The field’s net production for the month of June 2016 of 4.2 MBOED accounted for approximately 9% of our net production. Net proved reserves for the field were 83% oil at June 30, 2016.

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. There are 14 active wells located throughout the field. The field is produced from one central production platform and has produced in excess of 110 MMBOE. The field’s net production for the month of June 2016 of 1.5 MBOED accounted for approximately 3% of our net production. Net proved reserves for the field were 57% oil at June 30, 2016.

8

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 structural and stratigraphic traps against salt at depth. Minor faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 151 MMBOE. There are six production platforms and 28 active wells located throughout the field. The field’s net production for the month of June 2016 of 2.7 MBOED accounted for approximately 6% of our net production. Net proved reserves for the field were 70% oil at June 30, 2016.

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 457 MMBOE since production first began in 1963. We have 13 platforms and 31 active wells throughout the field. The field’s net production for the month of June 2016 of 3.2 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 79% oil at June 30, 2016.

West Delta 30 Field.  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 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 749 MMBOE. There are 45 production structures and 88 active wells located throughout the field. The field’s net production for the month of June 2016 of 5.7 MBOED accounted for approximately 13% of our net production. Net proved reserves for the field were 87% oil at June 30, 2016. This field is the third largest oil field on the GoM Shelf, based on cumulative production to date.

South Pass 78.  We operate and have 100% working interest in the South Pass 78 complex. Additional interest in the field was acquired through the EPL Acquisition. The complex is located 86 miles southeast of New Orleans. It contains 31 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 245 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 2016 of 3.6 MBOED accounted for approximately 8% of our net production. Net proved reserves for the field were 60% oil at June 30, 2016.

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 26 and 41 were 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 515 MMBOE since production began in 1957 with the exception of South Timbalier 41, discovered by EPL 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 23 major production platforms and 29 smaller structures located throughout the fields and 57 active wells. The area’s net production for the month of June 2016 of 2.0 MBOED accounted for approximately 4% of our net production. Net proved reserves for the field were 81% oil at June 30, 2016. This field is the tenth largest oil field on the GoM Shelf.

9

Reserve Estimation Procedures and Internal Controls over Reserve Estimates

For fiscal year 2016, 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 SEC staff interpretations and guidance and conform to ASC 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 Audit Committee (“Audit Committee”) of the Company’s Board of Directors (the “Board of Directors”) 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 issuance of the final reserves report, the Board of Directors meets with a representative of NSAI to review material variances, if any, between NSAI’s estimates and our 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;

• Internal reserves estimates are prepared by the area asset reservoir engineers and reviewed by asset team management;

• Ownership interests, working interests and net revenue interests used in the net reserves calculation are compared against the Well Master to ensure accuracy;

• Proved undeveloped property drilling (and/or development) schedules are reviewed and approved by the Audit Committee and certain members of senior management. At June 30, 2016, our reserve estimates do not include any proved undeveloped reserves;

• Senior management regularly reviews our drilling schedule and, after consultation and updates from the respective departments of the Company, approves any changes made to the existing long range plan and the related development plan. In addition, a comparison of actual proved undeveloped properties drilled (or developed) versus the associated previous fiscal year-end reserve report schedule is reviewed by the Board of Directors on a quarterly basis. This information is considered prior to approval of the current fiscal-year development schedule and associated reserves estimates;

• Material reserve variances are reviewed and approved by the Director of Reserves, 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 certain members of senior management;

• The Audit Committee reviews significant changes in our reserve estimates on an annual basis.

Qualifications of Primary Internal Engineer and Third Party Engineers

Our Director of Reserves, Lee I. Williams, is the technical person primarily responsible for overseeing the preparation of our internal reserves estimates and for coordinating reserves audits conducted by NSAI. He has 16 years of industry experience with positions of increasing responsibility and has over 13 years’ experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1998 with a Bachelor of Science Degree in Petroleum Engineering.

10

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, a Licensed Professional Engineer in the State of Texas (No. 100566), has been practicing consulting petroleum engineering at NSAI since 2006 and has over 4 years of prior industry experience. 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, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 11276), has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience. 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.

Technologies Used in Reserve Estimation

The SEC 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.

Third-Party Reserves Audit

The estimate of reserves disclosed in this Form 10-K for fiscal 2016 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 quantities and reserves categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.

In 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, 2016, based upon their evaluation concluding that our estimates of proved reserves were, in the aggregate, reasonable and were 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.

11

Summary of Oil and Gas Reserves at June 30, 2016

The following estimates of the net proved oil and natural gas reserves of our oil and natural 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 natural 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, 2016 Based on Average Fiscal-Year Prices
	Oil MMBbls		NGLs MMBbls		Natural Gas Bcf		MMBOE		Percent of Total Proved			PV-10 (in thousands)(1)(2)
Proved
Developed		62.1		4.2		121.1		86.6		100	%	$	58,353
Undeveloped		—		—		—		—		0	%		—
Total proved		62.1		4.2		121.1		86.6					58,353
Future income taxes													—
Less present value discount at 10%													—
Future income taxes discounted at 10%													—
Standardized measure of future discounted net cash flows												$	58,353

(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 but does not include effects, if any, of income taxes, as described below. PV-10 is not a financial measure prescribed under accounting principles generally accepted in the U.S. (“U.S. GAAP”); therefore, the table reconciles this amount to the standardized measure of discounted future net cash flows, which is the most directly comparable U.S. GAAP financial measure. Management believes that the non-U.S. GAAP financial measure of PV-10 is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 is used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. We believe the use of this pre-tax measure is valuable because there are unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under U.S. GAAP. Average prices (calculated using the average of the first-day-of-the-month commodity prices during the 12-month period ending on June 30, 2016) used in determining future net revenues were $39.63 per barrel of oil for West Texas Intermediate benchmark plus $3.06 per barrel for crude quality and location differentials, for a total of $42.69 per barrel. For NGL’s, the average price used was $18.38 per barrel. For natural gas, the average price used was $2.24 per MMBtu for Henry Hub benchmark less $0.30 per MMBtu for gas quality and location differentials, for a total of $1.94 per MMBtu.

(2) We recorded no future income taxes primarily due to forecasted tax losses and our inability to currently record any additional deferred tax assets. Further, in connection with our restructuring as a result of the Chapter 11 Cases, our ability to utilize our U.S. federal income tax net operating loss (“NOL”) carryforwards and the tax basis of our properties may have an impact on our standardized measure of discounted future net cash flows.

12

Changes in Proved Reserves

Our proved reserves decreased by 96.9 MMBOE or by approximately 53% from 183.5 MMBOE at June 30, 2015 to 86.6 MMBOE as of June 30, 2016. The decrease was primarily due to:

• Downward revision of 54.3 MMBOE related to reclassification of proved undeveloped reserves to the contingent resource category. Due to the depressed commodity price environment and our lack of capital resources to develop our properties, our proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result we removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category on December 31, 2015 are still economic at current prices, but were reclassified to the contingent resource category because they were no longer expected to be drilled within five years of initial booking due to current constraints on our ability to fund development drilling. Due to continued constraints on available capital, our proved reserve estimates do not include any proved undeveloped reserves as of June 30, 2016. Further, the reclassification of proved undeveloped reserves also had an impact on the proved developed reserves volumes as it shortened the economic life of fields and thereby reduced economic production from the proved developed reserves category.

• Production of 19.1 MMBOE during the year

• Downward revision of 28.7 MMBOE resulting from reduced oil and gas prices and shortened economic field life, and

• Downward revision of 8.1 MMBOE resulting from technical revisions

These were offset by:

• Reserve additions of 1.7 MMBOE, and

• Addition of 11.6 MMBOE due to acquisition of the remaining equity interests of M21K, LLC (“M21K”)

Decrease in our proved reserves had a significant impact on our estimated standardized measure values of the proved reserves which declined from approximately $2,757 million as of June 30, 2015 to approximately $58 million as of June 30, 2016, mainly due to the following:

• Reduction in average adjusted prices used in determining revenues from $73.79 per barrel of oil and $3.08 per MMBtu of natural gas at June 30, 2015 to $42.69 per barrel of oil and $1.94 per MMBtu of natural gas at June 30, 2016. The average prices are calculated using the average of the first-day-of-the-month commodity prices during the 12 month period in the fiscal year

• Reclassification of proved undeveloped reserves to contingent resource category, and

• The reduction in proved developed reserves value resulting from shorter economic field life due to the reclassification of proved undeveloped reserves to contingent resources which caused both a reduction in proved developed reserves volumes and significant acceleration of abandonment costs for all fields

These were offset in part by reduction in lease operating expenses, capital expenditures and undiscounted abandonment costs due to current market conditions.

13

Drilling Activity

The following table sets forth our drilling activity.

	Year Ended June 30,
	2016				2015				2014
	Gross		Net		Gross		Net		Gross		Net
Productive wells drilled
Development		1.0		1.0		21.0		21.0		12.0		12.0
Exploratory		—		—		3.0		1.7		—		—
Total		1.0		1.0		24.0		22.7		12.0		12.0
Nonproductive wells drilled
Development		—		—		1.0		1.0		—		—
Exploratory		—		—		1.0		0.6		1.0		1.0
Total		—		—		2.0		1.6		1.0		1.0

Present Activities

As of June 30, 2016, we had no wells being drilled.

Delivery Commitments

We had no delivery commitments in the three years ended June 30, 2016.

Productive Wells

Our working interests in productive wells were as follows:

	June 30,
	2016				2015
	Gross		Net		Gross		Net
Natural gas		103		76		86		65
Crude oil		532		436		481		438
Total		635		512		567		503

Acreage

Working interests in developed and undeveloped acreage were as follows:

	June 30, 2016
	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Onshore		11,499		2,905		95,774		52,866		107,273		55,771
Offshore		576,317		449,178		280,272		150,945		856,589		600,123
Total		587,816		452,083		376,046		203,811		963,862		655,894

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

	Year Ended June 30,
	2017				2018				2019
	Gross		Net		Gross		Net		Gross		Net
Onshore		19,694		7,007		3,445		499		4,276		1,195
Offshore		1,561		1,560		154,317		57,435		56,923		50,785
Total		21,255		8,567		157,762		57,934		61,199		51,980

14

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,
	2016		2015		2014
	(in thousands)
Property acquisitions
Proved	$	26,400	$	—	$	2,046,879
Unevaluated		—		2,304		924,882
Exploration costs		1,400		38,183		153,136
Development cost		57,400		608,605		632,262

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. For other selected financial data including operating revenues, net income and total assets, see “Item 6. Selected Financial Data.”

	Year Ended June 30,
	2016			2015			2014
Sales Volumes per Day
Natural gas (MMcf)		92.8			102.7			89.7
NGLs (MBbls)		2.5			2.7			2.4
Crude oil (MBbls)		34.5			39.1			27.7
Total (MBOE)		52.5			58.9			45.0
Percent of BOE from crude oil and NGLs		71	%		71	%		67	%
Average Sales Price
Natural gas per Mcf	$	2.04		$	3.13		$	4.15
NGLs per Bbl	$	16.09		$	28.09		$	40.78
Crude oil per Bbl	$	42.13		$	71.82		$	105.86
Sales price per BOE	$	32.07		$	54.41		$	75.44

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, 2016. Our average daily production, average sales prices and production costs are as follows:

	Year Ended June 30,
	2016			2015			2014
West Delta 73
Sales Volumes per Day
Natural gas (MMcf)		3.0			4.3			7.5
NGLs (MBbls)		0.1			0.1			0.1
Crude oil (MBbls)		4.8			4.9			4.1
Total (MBOE)		5.4			5.8			5.5
Percent of BOE from crude oil and NGLs		91	%		86	%		75	%
Average Sales Price
Natural gas per Mcf	$	2.34		$	3.46		$	4.22
NGLs per Bbl	$	14.72		$	25.18		$	40.74
Crude oil per Bbl	$	42.91		$	68.63		$	105.06
Production cost per BOE	$	16.99		$	19.91		$	19.76

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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,
	2016		2015		2014
Average Cost per BOE
Production costs
Lease operating expense
Insurance expense	$	1.98	$	1.86	$	1.90
Workover and maintenance		3.03		3.05		4.04
Direct lease operating expense		13.01		16.64		16.31
Total lease operating expense		18.02		21.55		22.25
Production taxes		0.08		0.39		0.33
Total production costs	$	18.10	$	21.94	$	22.58
Gathering and transportation	$	2.91	$	0.98	$	1.43
Depreciation, depletion and amortization rates	$	17.67	$	32.81	$	25.19

Derivative Activities

We have historically engaged in a hedging program designed to manage our commodity price risk and enhance cash flow certainty and predictability. On March 15, 2016, in connection with an amendment to our First Lien Credit Agreement, we unwound and monetized all of our outstanding crude oil and natural gas contracts and received $50.6 million, which was used to repay amounts outstanding under the agreement. At June 30, 2016, we had no outstanding derivative contracts. 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.

Trafigura Trading, LLC (“Trafigura”) accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2016. Chevron USA (“Chevron”) accounted for approximately 22% and 24% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015. Shell Trading Company (“Shell”) accounted for approximately 21%, 29%, and 45% of our total oil and natural gas revenues during the years ended June 30, 2016, 2015 and 2014, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 26%, and 43% of our total oil and natural gas revenues during the years ended June 30, 2015 and 2014, 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 Trafigura, Chevron or Shell curtailed their purchases. Although we believe we will be able to sell our production, prices may vary depending on demand.

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 natural gas has at times been limited or delayed due to restricted or unavailable transportation space or weather damage, and cash flow from the affected properties has been and could continue to be adversely impacted.

Competition

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and natural 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

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technical and personnel resources than ours. We actively compete with other companies when acquiring new leases or oil and natural 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. Our competitors may also have a greater ability to continue drilling activities during periods of low oil and natural gas prices, such as the current decline in oil prices, and to absorb the burden of current and future governmental regulations and taxation. 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 natural 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.

Government Regulation

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

Regulations affecting production.  The jurisdictions in which we operate generally require permits for drilling operations, drilling bonds and operating reports and impose other requirements relating to the exploration and production of oil and natural gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural 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 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 the U.S. 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 natural 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.

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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, 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

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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 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 natural gas leases in the Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the BOEM. These leases 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 may result in more stringent conditions and restrictions on activities that affect the environment. 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, decommission or remove platforms and pipelines, and clear the seafloor of obstructions at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. Historically, the BOEM and its predecessors could exempt the lessees from posting such bonds or other assurances for the performance of these decommissioning obligations. However, following the bankruptcy of another Gulf of Mexico operator in 2012, the BOEM commenced a reassessment of its offshore financial assurance program and, on July 14, 2016, the agency issued a new NTL regarding the need for additional security to satisfy decommissioning obligations. This newly issued NTL eliminated this exemption from the posting of financial assurances.

We are a lessee and operator of oil and natural gas leases on the OCS and consequently, as of June 30, 2016, we have submitted approximately $226.6 million in performance bonds in the form of general or supplemental bonds to the BOEM that may be accessed and used by the BOEM to assure our commitment to comply with our lease obligations, including decommissioning obligations. We also maintain approximately $161.4 million in performance bonds issued not to the BOEM but rather to predecessor third party assignors, including certain state regulatory bodies, of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Since April 2015, we have had a series of discussions

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and exchanges of information with the BOEM regarding our submittal of additional supplemental bonding or other financial assurance with respect to offshore oil and natural gas interests. For information related to our supplemental bonding or other financial assurance requirements and our long-term financial assurance plan, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — BOEM Supplemental Financial Assurance and/or Bonding Requirements.”

The future cost of compliance with our existing supplemental bonding requirements, including the obligations imposed upon us under our long-term financial assurance plan and the July 14, 2016 NTL, or any other changes to the BOEM’s rules that are applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. While we are currently in compliance, we can provide no future assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient operating cash flows to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may have any of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties and one or more of such actions could have a material effect on our business, prospects, results of operations, financial condition, and liquidity.

Under certain circumstances, for example, the failure to provide adequate security for decommissioning obligations, the BOEM may have our operations on federal leases to be suspended or cancelled. 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.

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.

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

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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;

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

• Endangered Species Act, Marine Mammal Protection Act, and Migratory Bird Treaty Act, which govern 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 relate to offshore oil and natural gas operations in U.S. waters and impose obligations for establishing financial assurances for decommissioning obligations, liabilities for pollution cleanup costs resulting from operations, and potential liabilities for pollution damages.

Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. Because environmental costs and liabilities occur frequently in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements may change and 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. We maintain insurance coverage for sudden and accidental spills and pollution emanating from our operations subject to time discovery and reporting limitations for third party damages, although we are not fully insured against all such risks. Our insurance coverage provides for the reimbursement to us of costs incurred from a well out of control for the containment and clean-up of materials that may be suddenly and accidentally released in the course of a scheduled well out of control as defined by the policy terms, but such insurance does not fully insure pollution and similar environmental risk.

The federal Clean Air Act and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to result in the emission of new or increased existing air pollutants, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in May 2016, the EPA announced final rules that establish new controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production activities, as part of an overall effort to reduce methane emissions by up to 45 percent in 2025. In a second example, in October 2015, the EPA issued a final rule under the federal Clean Air Act, lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and

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welfare, respectively. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country will use to achieve its greenhouse gas emissions targets. With regards to safety-related requirements, BSEE issued a final rule in April 2016 mandating more stringent design requirements and operational procedures for critical well control equipment used in oil and natural gas operations on the OCS. Among other things, this final rule imposes rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deep water and high temperature, high pressure drilling activities, establishment of safe drilling margins with respect to downhole mud weights that may be used during drilling activities, and enhanced reporting requirements to regulators. These recent EPA and BSEE-adopted rules, or any other future laws or rules, which impose more stringent environmental or safety-related requirements in connection with our offshore oil and natural gas exploration and production operations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows.

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 assigns joint and several, strict liability, without regard to fault, to each responsible party, 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, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In 2014, the BOEM issued a final rule that raised OPA’s damages liability cap to $133.65 million. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required under OPA 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.  The EPA has 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. Among the EPA’s rules regulating greenhouse gas emissions, one requires a reduction in emissions of greenhouse gases from motor vehicles and another requires preconstruction and operating permits for certain large stationary sources of such emissions. 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, in June 2016, the EPA published a final rule that establishes new controls for methane and volatile organic compounds emissions from new, modified or reconstructed oil and natural gas production sources and natural gas processing and transmission sources.

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 that correspond to their annual emissions of greenhouse gases. The adoption of legislation or regulatory programs to reduce emissions

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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 251 employees at June 30, 2016, none of which were represented by labor unions or covered by any collective bargaining agreement. We consider relations with our employees to be satisfactory and we have never experienced a work stoppage or strike. We regularly use independent consultants and contractors to perform various professional services in various areas, including in our exploration and development operations, production operations and certain administrative functions.

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. Court filings and other information related to the Bankruptcy Petitions are available at a website administered by our claims agent, Epiq Systems, at http://dm.epiq11.com/EnergyXXI, or via our Restructuring Hotline at (844) 807-7712 (toll free) or (503) 520-4464 (international). As a result of the Chapter 11 Proceedings, we no longer make available 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 filed with, or furnished to, the SEC, however we will voluntarily provide electronic or paper copies of our filings free of charge upon request. 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

We are subject to risks and uncertainties associated with our Chapter 11 proceedings.

Our operations and ability to develop and execute our business plan, our financial condition, our liquidity and our continuation as a going concern, are subject to the risks and uncertainties associated with our Chapter 11 proceedings. These risks include the following:

• our ability to execute, confirm and consummate the Plan or another plan of reorganization with respect to the Chapter 11 proceedings;

• the high costs of bankruptcy proceedings and related fees;

• our ability to obtain sufficient financing to allow us to execute our business plan post-emergence from Chapter 11;

• our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;

• our ability to maintain contracts that are critical to our operations;

• our ability to execute our business plan in the current depressed commodity price environment;

• our ability to attract, motivate and retain key employees;

• the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

• the ability of third parties to seek and obtain court approval to convert the Chapter 11 proceedings to a Chapter 7 proceeding; and

• the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 proceedings that may be inconsistent with our plans.

Delays in our Chapter 11 Cases increase our risks of being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the continued administration of the Chapter 11 Cases. For example, the UCC filed the Emergency Motion of the Official Committee of Unsecured Creditors for Order Vacating Disclosure Statement Order Pursuant to Fed. R. Bankr. P. 9024 [Docket No. 1236] (the “Motion to Vacate”) on September 7, 2016. Specifically, the Motion to Vacate seeks to vacate the Disclosure Statement based on the testimonial evidence that the independent directors at EGC and EPL had provided. The Debtors filed an objection [Docket No. 1280] to the Motion to Vacate on September 13, 2016 because, among other things, the UCC, in the Motion to Vacate, quotes portions of the Disclosure Statement and depositions out of context, makes unsupportable statements regarding the role of the independent directors at EGC and EPL and improperly suggests that there are false statements contained in the Disclosure Statement. If the Bankruptcy Court grants the Motion to Vacate, the Debtors’ could be required to re-solicit votes on confirmation of the Plan. Resolicitation would significantly delay confirmation of the Debtors’ Plan and their exit from Chapter 11. During the status conference on September 13, 2016, following which, the Bankruptcy Court ordered the parties to engage in mediation and continued the hearing on the Motion to Vacate to be heard in conjunction with the hearing to consider confirmation of the Plan (the “Confirmation Hearing”).

These risks and uncertainties surrounding the Chapter 11 process and the various motions and objections raised in the proceedings could affect our business and operations in various ways. For example, negative events or publicity associated with our Chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. We also need the Bankruptcy Court to approve the confirmation of the Plan. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 Cases will have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

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We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. However, even if our Plan meets other requirements under the Bankruptcy Code, creditors may not vote in favor of our Plan, and certain parties in interest have filed objections to the Plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Even if the requisite acceptances of our Plan are received from creditors entitled to vote on the Plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, preferred or common stock).

If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.

Even if the Plan or another Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and natural gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other Chapter 11 plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our Chapter 11 proceedings. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

Our ability to continue as a going concern may be dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if the Plan is confirmed.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution.

Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to change substantially our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and

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it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

We have substantial liquidity needs, including substantial capital requirements, and we may not be able to obtain sufficient liquidity to confirm a plan of reorganization and exit bankruptcy.

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. Our capital requirements depend on numerous factors making it difficult to predict the timing and amount of such capital expenditures. We intend to primarily finance our near term capital expenditures with cash on hand. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. The Company believes it has sufficient liquidity, including approximately $203 million of cash on hand as of June 30, 2016 and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 proceedings for minimum operating and capital expenditures and for working capital purposes excluding principal and interest payments on our outstanding debt. However, given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our operations, our liquidity needs could be significantly higher than we currently anticipate. Our ability to maintain adequate liquidity through the reorganization process and beyond depends on our ability to successfully implement the Plan (or another Chapter 11 plan), successful operation of our business, and appropriate management of operating expenses and capital spending. Our anticipated liquidity needs are highly sensitive to changes in each of these and other factors. If we are unable to meet our liquidity needs, we may have to take other actions to seek additional financing to the extent available or we could be forced to consider other alternatives to maximize potential recovery for the creditors, including a possible sale of the Company or certain material assets pursuant to Section 363 of the Bankruptcy Code, or a liquidation under Chapter 7 of the Bankruptcy Code.

Our expected Exit Facility (as defined below) and liquidity upon emergence will limit our available funding for exploration and development. We may have difficulty obtaining additional credit, which could adversely affect our operations and financial position.

Historically, we have depended on our Revolving Credit Facility for a portion of our future capital needs. As of June 30, 2016, we had borrowed $99.4 million and had $227.8 million in letters of credit issued under our Revolving Credit Facility, with no remaining available borrowing capacity.

Our Restructuring Support Agreement, provides that the Debtors, on behalf of the holders of claims (the “First Lien Claims”) arising on account of the Revolving Credit Facility and subject to further negotiations with the Lenders under the Revolving Credit Facility, will use their best efforts to ensure that at emergence from Chapter 11, the amount drawn under the Revolving Credit Facility either (i) remains outstanding or (ii) is refinanced with a new facility with terms acceptable to the Restructuring Support Parties who hold, in aggregate, at least 66.6% in principal amount of the claims relating to the Second Lien Notes (the “Second Lien Notes Claims”) held by the Restructuring Support Parties (the “Majority Restructuring Support Parties”); provided, however that (a) $227.8 million of letters of credit usage remains outstanding and (b) other terms, including a borrowing base redetermination holiday, are acceptable to the Debtors and the Majority Restructuring Support Parties. If the Debtors are unable to obtain the foregoing treatment of the First Lien Claims, then the Debtors will use their best efforts to obtain treatment acceptable to the Debtors and the Majority Restructuring Support Parties.

As contemplated by the Exit Facility Term Sheet with the Lenders under the Revolving Credit Facility attached to the Plan as Exhibit 1 (the “Exit Facility Term Sheet”), which is subject to change and to be

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considered in connection with Plan confirmation, we anticipate that the reorganized company (the “New Entity”) will enter into new exit financing (the “Exit Facility”) comprised of the following tranches: (i) conversion of the remaining drawn amount, net of related restricted cash, of approximately $69 million plus accrued default interest into a new term loan (the “Exit Term Loan”) with the New Entity and (ii) the conversion of the former EGC tranche of the Revolving Credit Facility into a new EGC sub-facility (the “EGC Facility”). The Exit Term Loan will have a maturity of three years with an annual interest rate of LIBOR plus 4.5%, payable monthly. The EGC Facility will have a maturity of three years with an annual interest rate of 4.5%, payable on a schedule consistent with the Revolving Credit Facility. Existing letters of credit may be renewed or replaced (in each case, in an outstanding amount not to exceed the outstanding amount of the existing letter of credit). Availability under the Exit Facility will be permanently reduced by one-half of the amount of any reduction resulting from replacement or cancellation of an outstanding letter of credit. Any amount of cancellation or reduction that does not permanently reduce capacity will be available for the New Entity to fund new liquidity (the “New Funded Debt”). Such New Funded Debt in excess of $25 million will be subject to borrowing base redetermination. Pursuant to the Exit Facility, the New Entity and its subsidiaries will be subject to certain financial maintenance covenants and, in the case of the Exit Term Loan, amortization covenants.

In addition, upon our emergence from the Chapter 11 Cases, we are required under the Exit Facility to have liquidity of at least $90 million per the Exit Facility Term Sheet (the “Minimum Cash Balance”). While we expect the Exit Facility and Minimum Cash Balance described above to be available under the Plan, we may not be able to access adequate funding in the future as there will be no remaining available borrowing capacity contemplated under the Exit Facility, and there is no certainty that any new capacity will be created or that the Exit Facility may be refinanced on economically advantageous terms, and the Minimum Cash Balance and cash from operations may not be sufficient to otherwise fund our operations.

If funding is not available when needed, or is available only on unfavorable terms, it could adversely affect our development plans as currently anticipated, which could have a material adverse effect on our production, revenues and results of operations.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in our Plan because of, among other things: (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

Our common stock has been delisted from trading on the NASDAQ, has no longer been listed on a national securities exchange effective May 19, 2016, and is traded only in the over-the-counter market, which could negatively affect our stock price and liquidity.

On April 14, 2016, we received a letter from The NASDAQ Listing Qualifications Staff (the “Staff”) stating that the Staff had determined that our securities would be delisted from NASDAQ. After the suspension period, our common stock was formally delisted from NASDAQ on May 19, 2016. The decision was reached by the Staff under NASDAQ Listing Rules 5101, 5110(b) and IM-5101-1 as a result of our announcement that we had filed the Bankruptcy Petitions, the associated public interest concerns raised by the Bankruptcy Petitions, concerns regarding the residual equity interest of the existing listed securities holders and concerns about our ability to sustain compliance with all requirements for continued listing on NASDAQ. On February 24, 2016, we received a deficiency notice from NASDAQ stating that, based on the closing bid price of the our common stock for the last 30 consecutive business days, our common stock no longer met the minimum $1.00 per share requirement under NASDAQ Listing Rule 5450(a)(1). Because we did not request

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an appeal, trading of our common stock was suspended at the opening of business on April 25, 2016, and a Form 25-NSE was filed with the SEC on May 19, 2016, which removed our securities from listing and registration on NASDAQ.

As previously described, pursuant to the Restructuring Support Agreement entered into on April 11, 2016, it is expected that the dissolution of Energy XXI Ltd will be completed under the laws of Bermuda, following the confirmation of the Plan by the Bankruptcy Court, and, given that it is unlikely to have assets available for distribution, existing equity holders would receive no distributions in respect of that equity in that dissolution. Accordingly any trading in shares of our common stock during the pendency of the Chapter 11 proceedings is highly speculative.

Our securities resumed trading on the OTC Markets Group Inc.’s OTC Pink under the symbol “EXXIQ” on April 25, 2016. The OTC Pink is a significantly more limited market than NASDAQ, and the quotation of our common stock on the OTC Pink may result in a less liquid market available for existing and potential shareholders to trade shares of our common stock. This could further depress the trading price of our common stock and could also have a long-term adverse effect on our ability to raise capital. There can be no assurance that any public market for our common stock will exist in the future or that we will be able to relist our common stock on a national securities exchange. In connection with the delisting of our common stock, there may also be other negative implications, including the potential loss of confidence in us by suppliers, customers and employees and the loss of institutional investor interest in our common stock.

We believe it is highly likely that the shares of our existing common and preferred stock will be extinguished in accordance with Bermuda law following our Chapter 11 proceedings.

The Plan provides that the dissolution of Energy XXI Ltd will be completed under the laws of Bermuda, and, given that it is unlikely to have assets available for distribution, existing equity holders would receive no distributions in respect of that equity in that dissolution. Accordingly, any trading in shares of our common and preferred stock during the pendency of the Chapter 11 proceedings is highly speculative.

We may be subject to claims that will not be discharged in our Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a Chapter 11 plan of reorganization discharges a debtor from substantially all debts arising prior to the Petition Date. With few exceptions, all claims that arose prior to Petition Date (i) would be subject to compromise and/or treatment under the plan of reorganization and (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Additionally, under section 365 of the Bankruptcy Code, we are obligated to pay any amounts required to “cure” any defaults or breaches in contracts we seek to assume upon emergence from Chapter 11. These “cure” costs may render certain of our contracts uneconomic, which would likely lead us to reject such contracts. Both the potential cure costs and/or the rejection of such contracts as well as the assertion of any claims not ultimately discharged by the Plan could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

As a result of the Plan, NOL and other tax attributes are not expected to be available upon emergence from the Chapter 11 proceedings.

Certain tax attributes, such as NOL carryforwards and depletable and depreciable basis, are expected to be reduced as a result of the Plan. Under the Internal Revenue Code of 1986, as amended, tax attributes are reduced to the extent cancellation of indebtedness income is excluded from gross income arising from the Chapter 11 Cases (the “Tax Attribute Reduction Rules”). We currently project that all consolidated NOL carryforwards will be eliminated and other tax attributes will be substantially reduced under the Tax Attribute Reduction Rules. As a result, any pre-emergence NOL carryforwards and certain other tax attributes are not expected to be available to reduce our taxable income for tax periods beginning after emergence from the Chapter 11 Cases.

Our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and

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claims assessments may significantly impact our consolidated financial performance. As a result, our historical financial performance is likely not indicative of our financial performance after the Petition Date.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to our historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to the Plan. We expect to apply fresh start accounting in accordance with U.S. GAAP, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

The pursuit of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management and will impact how our business is conducted, which may have an adverse effect on our business and results of operations.

A long period of operating under Chapter 11 could adversely affect our business and results of operations. While the Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort focusing on the proceedings. This diversion of attention may materially affect the conduct of our business adversely, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 Cases are protracted.

We may not meet certain conditions of the Restructuring Support Agreement, which could result in the automatic termination of such agreement.

We entered into the Restructuring Support Agreement with the Second Lien Noteholders in connection with the filing of the Bankruptcy Petitions on April 14, 2016. Following subsequent negotiations between the Debtors and the Second Lien Noteholders, on September 13, 2016, the Debtors and the Second Lien Noteholders entered into the Fifth Amendment to the Restructuring Support Agreement (the “Fifth RSA Amendment”), which provided, among other things, that the Debtors file an amended Plan to reflect the terms of the Fifth RSA Amendment. We may not be able to meet certain conditions of the Restructuring Support Agreement, which could cause a Restructuring Support Party Termination Event, as defined in the Restructuring Support Agreement, which could cause the automatic termination of the Restructuring Support Agreement.

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 developing, finding or acquiring additional reserves that are economically recoverable. If we are unable to replace reserves through drilling or acquisitions on economic terms, our level of production and cash flows will be adversely affected. In general, production from oil and natural 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. We ceased development drilling activities in September 2015 as a result of our liquidity constraints at that time. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves continues to be impaired as the extent of cash flow from operations is reduced and external sources of capital are extremely 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 explore for, develop or acquire additional reserves.

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.

Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. For example, oil prices declined severely during our 2015 fiscal year with continued lower prices throughout fiscal year 2016. The WTI crude oil price per barrel for the period from October 1, 2014 to June 30, 2016 ranged from a high of $91.01 to a low of $26.21, a decrease of 71.2%, and the NYMEX

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natural gas price per MMBtu for the period October 1, 2014 to June 30, 2016 ranged from a high of $4.49 to a low of $1.64, a decrease of 63.5%. As of June 30, 2016, the spot market price for WTI was $48.33. 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 production activity;

• 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, Africa 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.

Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. The speed and severity of the decline in oil prices during our 2015 fiscal year and the continued lower prices throughout our fiscal year 2016 has materially affected our results of operations and our estimates of our proved oil and natural gas reserves. Any sustained periods of low prices for oil and natural gas are likely to materially and adversely affect our financial position, the quantities of oil and natural gas reserves that we can economically produce, our cash flow available for capital expenditures and our ability to access funds through the capital markets, if they are available at all.

We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially have negative impact on operating cash flows.

To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells, decommission and remove platforms and pipelines, and clear the seafloor of obstructions at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. Historically, the BOEM and its predecessors could exempt the lessees from posting such bonds or other assurances for the performance of these decommissioning obligations. However, following the bankruptcy of another Gulf of Mexico operator in 2012, the BOEM commenced a reassessment of its offshore financial assurance program and, on July 14, 2016, the agency issued a new Notice to Lessees and Operators (“NTL”) regarding the need for additional security to satisfy decommissioning obligations. This newly issued NTL eliminated this exemption from the posting of financial assurances.

We are a lessee and operator of oil and natural gas leases on the OCS and consequently, as of June 30, 2016, we have submitted, approximately $226.6 million in performance bonds in the form of general or supplemental bonds to the BOEM that may be accessed and used by the BOEM to assure our commitment to comply with our lease obligations, including decommissioning obligations. We also maintain approximately $161.4 million in performance bonds issued not to the BOEM but rather to predecessor third party assignors, including certain state regulatory bodies, of certain of the wells and facilities on these leases pursuant to a

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contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities.

In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for exemption from certain supplemental bonding requirements for potential offshore decommissioning obligations and that certain of our subsidiaries must provide approximately $1,000 million in supplemental bonding or other financial assurance for our offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In October 2015, we received information from the BOEM that we could receive additional demands of supplemental bonding or other financial assurance for amounts in addition to the $1,000 million initially sought by the BOEM in April 2015, primarily relating to certain leases in which we have a legal interest that were no longer exempt from supplemental bonding as a result of co-lessees losing their exemptions. Since April 2015, we have had a series of discussions and exchanges of information with the BOEM regarding our submittal of additional supplemental bonding or other financial assurance with respect to offshore oil and natural gas interests that has resulted in, among other things the BOEM’s agreement to, and execution of, the long-term financial assurance plan on February 25, 2016 (the “Long-Term Plan”) that is intended to address the supplemental bonding and other financial assurance concerns expressed to us by the BOEM in April and October 2015.

Pursuant to the Restructuring Support Agreement entered into on April 11, 2016, it is anticipated that we will continue to perform our obligations under the Long-Term Plan during the pendency of the Chapter 11 Cases and in connection with the consummation of our restructuring. We submitted an amended and supplemental plan to the BOEM on June 28, 2016 and are currently awaiting their further response.

Notwithstanding the BOEM’s July 14, 2016 NTL, the BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. In addition, BSSE recently increased its estimates of many offshore operator’s plugging and abandonment costs, including EXXI, which could result in the BOEM requesting additional bonding with respect to those properties. EXXI believes that such increases do not accurately reflect actual costs of plugging and abandonment and, to date, BOEM has not indicated that it will increase bonding requirements as a result of the increase in BSSE estimates, however, there is no certainty that BOEM will not alter bonding obligations in the future. The cost of compliance with our existing supplemental bonding requirements, including the obligations imposed on us under the Long-Term Plan and the July 14, 2016 NTL, any other future BOEM directives, or any other changes to the BOEM’s rules applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, although we currently have $49.3 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors, we may be required to provide additional cash collateral in the future to support the issuance of such bonds or other financial security. While we are currently in compliance, we can provide no future assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient operating cash flows to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BSEE or the BOEM may have any of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties and one or more of such actions could have a material effect on our business, prospects, results of operations, financial condition, and liquidity.

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

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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, current operators in the U.S. Gulf of Mexico are required to commence decommissioning activities more quickly than was the case prior to the BOEM’s issuance of an NTL in 2010 addressing 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. The idle iron NTL requires that 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, with a two-year delay of such activities available under certain circumstances. 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.

New regulatory initiatives imposing more stringent environmental or safety-related requirements could cause us to incur increased capital expenditures and operating costs, which could be significant.

The federal Clean Air Act and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to result in the emission of new or increased existing air pollutants, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in April 2016, the BOEM published a proposed rule regarding air emissions controls for oil and natural gas operations on the OCS, which rule would, among other things: (i) require the reporting and tracking of all pollutants defined by the EPA to affect human health and public welfare; (ii) apply the National Ambient Air Quality Standards (“NAAQS”) to all offshore facility and related support vessel emissions; and (iii) establish new recordkeeping and performance measure criteria. In a second example, in October 2015, the EPA issued a final rule under the federal Clean Air Act, lowering the NAAQS for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country will use to achieve its greenhouse gas emissions targets. With regards to safety-related requirements, the BSEE published a final rule in April 2016 mandating more stringent design requirements and operational procedures for critical well control equipment used in oil and natural gas operations on the OCS. Among other things, this final rule imposes rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deep water and high temperature, high pressure drilling activities, establishment of safe drilling margins with respect to downhole mud weights that may be used during drilling activities, and enhanced reporting requirements to regulators. These recent EPA and BSEE-proposed and adopted rules, or any other future laws or rules, which impose more stringent environmental or safety-related requirements in connection with our offshore oil and natural gas exploration and production operations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows.

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Lower oil and gas prices and other factors may result in future ceiling test write-downs 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 natural 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 natural gas properties, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization. As of the reported balance sheet date, our capitalized costs may not exceed the full cost limitation calculated under the above described rule based on the average prices for oil and natural gas.

The recent declines in oil prices have adversely affected our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce. For the year ended June 30, 2016, we recognized ceiling test write-downs of our oil and natural gas properties totaling $2,813.6 million.

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 at the time of the estimate. Unless commodity prices or reserves increase, the estimated discounted future net cash flows from our proved reserves would generally be expected to decrease. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

• supply of and demand for oil and natural gas;

• actual prices we receive for oil and natural gas;

• the volume, pricing and duration of any future oil and natural gas hedging contracts;

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

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

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas 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 oil and natural gas 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.

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

This Form 10-K contains estimates of our proved oil and natural 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 natural gas that will ultimately be recovered may differ materially from the estimated quantities and

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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 natural gas reserves most likely will vary from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

We are limited in our ability to book 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, 2016 prepared in a manner consistent with our interpretation of the SEC rules relating to 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 limits our potential to book proved undeveloped reserves as we pursue our drilling program.

Delays in the development of our reserves or increases in costs to drill and develop such reserves reduced the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and has resulted in some projects becoming uneconomic. For example, our proved reserves of 86.6 MMBOE and $58.4 million of PV-10 as of June 30, 2016 were lower than our proved reserves of 183.5 MMBOE and $2,834.4 million of PV-10 as of June 30, 2015 in part due to the rescheduling or write off of certain of our reserves as a result of lower oil and natural gas prices and reductions in our capital expenditure budget as compared to our June 30, 2015 reserve report. Due to the depressed commodity price environment and our lack of capital resources to develop our properties, our proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result we removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Further, the reclassification of proved undeveloped reserves also had an impact on the proved developed reserves volumes as it shortened the economic life of fields and thereby reduced economic production from the proved developed reserves category. Almost all of the proved undeveloped reserves that were removed from the proved category on December 31, 2015 are still economic at current prices, but were reclassified to the contingent resource category because they were no longer expected to be drilled within five years of initial booking due to current constraints on our ability to fund development drilling. Due to continued constraints on available capital, our proved reserve estimates do not include any proved undeveloped reserves as of June 30, 2016. Please read “Business — Development of Proved Undeveloped Reserves.”

As of June 30, 2016, approximately 22% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be 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 produced. Furthermore, there can be no assurance that all of our 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.

Production periods or reserve lives for Gulf of Mexico properties may 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

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reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.

Our 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.

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.

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 in the GoM Shelf, which activities 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 natural 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;

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• 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 natural gas leaks, oil spills, pipeline ruptures and unauthorized 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 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 do not carry 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.

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. Please also read “— We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations which may be costly and could potentially have a negative impact on operating cash flows.”

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, including with respect to commodity prices such as for oil and natural gas, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only

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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. If storm activity in the future is severe, insurance underwriters may not offer the type and level of coverage previously insured, and costs and retentions may increase substantially. In addition, we do not have, and it is unlikely we will obtain, 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.

Although we currently have no Weather Based Insurance Linked Securities (“Securities”) in place, in the future we may utilize these Securities to supplement our windstorm insurance coverage to mitigate potential loss to our most valuable oil and natural 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 natural 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 natural 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 natural 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 natural 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. The competitors may also have a greater ability to continue drilling activities during periods of low oil and natural gas prices, such as the current commodity price environment, and to absorb the burden of current and future governmental regulations and taxation. 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 natural 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.

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

Market conditions (including with respect to commodity prices such as for oil and natural gas), 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 natural gas production depends on a number of factors, including the demand for and supply of oil and natural 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

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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 natural 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.

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. We have leases on 21,255 gross acres (8,567 net) that could potentially expire during fiscal year 2017.

Our drilling plans for areas not currently held by production are subject to change based upon various factors. Many of these factors 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.

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 any drilling program post-emergence from Chapter 11, we will not serve as operator of all planned wells. We operated approximately 89% of our proved reserves at June 30, 2016. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

• the timing and amount of capital expenditures;

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

• the operator’s expertise and financial resources;

• approval of other participants in drilling wells;

• selection of technology; and

• the rate of production of the reserves.

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

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

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties

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

We sell the majority of our production to three customers.

Trafigura, Chevron and Shell each accounted for approximately 22%, 22% and 21%, respectively, of our total oil and natural gas revenues during the year ended June 30, 2016. Our inability to continue to sell our production to Trafigura, Chevron or Shell, if not offset by sales with new or other existing customers, could have a material adverse effect on our business and operations.

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.

Any future 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. Any future shortages or 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.

We do not have hedges to cover our exposure to reductions in oil and natural gas prices.

Currently, we do not have any hedges in place to cover our exposure to reductions in oil and natural gas prices, such as purchased futures contracts or other hedging strategies. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices which would have a material negative impact on our results of operations. While the use of hedging transactions limits the downside risk of price declines, their use also may limit future revenues from price increases.

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

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

Under any price risk management activities that we may enter in in the future, 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

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

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

• production is less than expected;

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

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

During periods of declining commodity prices, our commodity price derivative positions may increase, which would increase our counterparty exposure.

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. 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.

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

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business. If our senior management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

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

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

We may not realize all of the anticipated benefits from our 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, including with respect to commodity prices such as for oil and natural gas.

For example, following the EPL Acquisition, commodity prices significantly declined, and we have experienced a sustained low commodity price environment. As a result of the significant decline in commodity prices, we have not realized the revenue enhancements that we originally anticipated from the EPL Acquisition and have had to service substantial additional debt that was incurred in connection with funding the EPL Acquisition.

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 decommissioning obligations; 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 offshore. 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.

Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill response plans, and other related restrictions arising after the Deepwater Horizon incident in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

In response to the Deepwater Horizon incident in the Gulf of Mexico in April 2010, BSEE and BOEM, each agencies of the U.S. Department of the Interior, have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. These governmental agencies have also implemented and enforced new rules, NTLs and temporary drilling

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moratoria that imposed safety and operational performance measures on exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation of drilling activities. Compliance with these added and more stringent regulatory restrictions in addition to any uncertainties or inconsistencies in current decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development and oil spill response plans could adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, are developing and implementing new, more restrictive requirements such as, for example, the April 2016 final rule on well control was published by the BSEE, which rule, among other things, imposes rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deep water and high temperature, high pressure drilling activities, establishment of safe drilling margins with respect to downhole mud weights that may be used during drilling activities, and enhanced reporting requirements to regulators.

Among other adverse impacts, these additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities. If similar material spill incidents were to occur in the future, the United States or other countries could elect again to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development. We cannot predict the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such 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.

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 the U.S. 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 natural 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 may 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 or performance bonds, and reports concerning operations and impose other requirements relating to the

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exploration and production of oil and natural gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural 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 natural 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 natural 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

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some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.

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

• require the acquisition of a permit before drilling commences;

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

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

• impose substantial liabilities for pollution resulting from operations.

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

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

• incurring investigatory or remedial obligations; and

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

Changes in environmental laws and regulations or how they are interpreted or applied 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. While, historically, our environmental compliance costs have not had a material adverse effect on our results of operations, there can be no assurance that such costs will not be material in the future. 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

44

position, cash flows, and results of operations. If FERC’s ratemaking methodology changes, the new methodology could also result in tariffs that generate lower revenues and cash flow.

Based on the way our oil pipelines are operated, we believe that the only transportation on our pipelines that is subject to the jurisdiction of FERC is the transportation specified in the tariffs 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.

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

FERC, the FTC and the CFTC hold statutory authority to regulate certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these commodities, we are required to observe and comply with these anti-fraud and anti-manipulation regulations. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

The EPA has 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. Among the EPA’s rules regulating greenhouse gas emissions, one requires a reduction in emissions of greenhouse gases from motor vehicles and requires preconstruction and operating permits for certain large stationary sources of such emissions. 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, in June 2016, the EPA published a final rule that establishes new controls for methane and volatile organic compounds emissions from new, modified or reconstructed oil and natural gas production sources and natural gas processing and transmission sources.

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 that correspond to their annual emissions of greenhouse gases.

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

45

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. Our offshore operations are particularly at risk from severe 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 the U.S. 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.

The U.S. 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 with whom we may enter into derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the original 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 any future derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our future use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas liquids and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas liquids and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

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 natural 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

46

technologies needed to extract oil and natural gas in increasingly difficult physical environments, such as the ultra-deep trend, and global competition for oil and natural 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 natural gas resources;

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

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

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

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

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

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

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

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

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

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

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Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

The Budget of the United States Government, Fiscal Year 2017, among other proposed legislation, contains recommendations that, if enacted into law, would eliminate certain U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Several bills have been introduced in the U.S. 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.

Additionally, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose a fee of $10.25 per barrel-equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products, and would be phased in evenly over five years, beginning October 1, 2016. The adoption of this or similar proposals could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could adversely affect our financial position, results of operations and cash flows.

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. Most of our pending legal proceedings have been stayed by virtue of filing the Bankruptcy Petitions on April 14, 2016. 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. For more information regarding the Chapter 11 proceedings, see Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources” of Notes to our Consolidated Financial Statements in this Form 10-K.

SEC Proof of Claim

On June 17, 2016 the SEC filed a proof of claim against the Company asserting a general unsecured claim in the amount of $3.9 million based on alleged violations of the federal securities laws by Energy XXI pertaining to the failure to disclose certain funds borrowed by John D. Schiller, Jr. from personal acquaintances or their affiliates, certain of whom provided Energy XXI and certain of its subsidiaries with services and Mr. Schiller’s pledge of Energy XXI stock to a certain financial institution in the second half of 2014. If allowed, such claim against Energy XXI would be classified as a general unsecured claim under the Plan and would be subject to discharge, settlement, and release in connection with the Chapter 11 Cases, and receive the treatment provided to holders of general unsecured claims. The Debtors anticipate that they will object to the SEC’s claim.

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”). We were listed on NASDAQ under the symbol “EXXI” prior to the suspension of our common stock from trading at the opening of business on April 25, 2016, in connection with the commencement of the Chapter 11 proceedings. Our common stock resumed trading on the OTC Markets Group Inc.’s OTC Pink (the “OTC Pink”) under the symbol “EXXIQ” on April 25, 2016. After the suspension period, our common stock was formally delisted from NASDAQ on May 19, 2016. 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 or OTC Pink, as applicable.

	Unrestricted Common Stock
	High		Low
Fiscal 2015
First Quarter	$	23.55	$	11.35
Second Quarter		11.13		2.45
Third Quarter		4.83		2.33
Fourth Quarter		4.61		2.63
Fiscal 2016
First Quarter		2.49		0.95
Second Quarter		2.30		1.00
Third Quarter		1.38		0.33
April 1, 2016 to April 24, 2016		0.71		0.13
April 25, 2016 to June 30, 2016		0.14		0.04

As of September 9, 2016, there were approximately 343 holders of record of our common stock.

Concurrently with the filing of the Bankruptcy Petitions pursuant to the Restructuring Support Agreement and to streamline the business operations and organization structure following the emergence from Chapter 11 proceedings, Energy XXI Ltd filed a petition to commence an official dissolution under the laws of Bermuda before the Supreme Court of Bermuda (the “Bermuda Proceeding”). On April 15, 2016, John C. McKenna was appointed as provisional liquidator by the Supreme Court of Bermuda. The Bermuda Proceeding is a limited ancillary proceeding under which dissolution of Energy XXI Ltd will be completed following the confirmation of the bankruptcy plan by the Bankruptcy Court, accordingly, the Bankruptcy Court retains primary jurisdiction over Energy XXI Ltd during the Chapter 11 proceedings.

On June 3, 2016, the Bermuda Court granted the Debtors’ request to adjourn the Bermuda Proceeding through November 4, 2016. Assuming that there are no assets available for distribution to equity under the Bermuda laws governing the payment of stakeholders in a Bermuda dissolution, existing equity holders would not receive distribution in respect of their equity interests in that dissolution. Accordingly any trading in shares of our common stock during the pendency of the Chapter 11 Cases is highly speculative.

Dividend Information

We paid cash dividends of $0.01 per share to holders of our common stock on March 13, 2015 and June 12, 2015. We paid cash dividends of $0.12 per share to holders of our common stock on September 12, 2014 and December 12, 2014. Late in fiscal year 2015, our Board of Directors decided to suspend the declaration of quarterly dividends on our common stock for the foreseeable future.

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

We have suspended the repurchase program indefinitely to reduce our capital needs. We did not make any repurchases under our repurchase program during the fiscal years ended June 30, 2016 and 2015. 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. These repurchases included an additional one time repurchase of our common stock approved by our Board of Directors 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, which occurred concurrently with the offering of our 3.0% Senior Convertible Notes. As of June 30, 2016, $83.2 million remained available for repurchases under the share repurchase program.

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Item 6. Selected Financial Data

We have derived the following selected consolidated financial information as of June 30, 2016 and 2015 and for the years ended June 30, 2016, 2015 and 2014 from the audited consolidated financial statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” You should read the selected consolidated historical financial information set forth below in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and with the audited consolidated financial statements and the notes thereto included in Part II, Item 8, “Financial Statements and Supplementary Data,” of this Form 10-K.

	Year Ended June 30,
	2016			2015			2014(3)			2013			2012
	(In thousands, except per share amounts)
Income Statement Data
Revenues	$	706,527		$	1,405,452		$	1,153,123		$	1,158,932		$	1,504,611
Depreciation, depletion and amortization (“DD&A”)		339,516			705,521			414,026			363,791			350,569
Impairment of oil and natural gas properties		2,813,570			2,421,884			—			—			—
Goodwill impairment		—			329,293			—			—			—
Operating income (loss)		(3,017,425	)		(2,710,891	)		217,806			326,081			694,158
Other income (expense) – net(1)		1,112,788			(336,297	)		(164,661	)		(112,704	)		(108,811	)
Net income (loss)		(1,918,751	)		(2,433,838	)		18,125			180,783			478,808
Basic earnings (loss) per common share	$	(20.11	)	$	(25.97	)	$	0.09		$	2.14		$	5.95
Diluted earnings (loss) per common share	$	(20.11	)	$	(25.97	)	$	0.09		$	1.94		$	5.27
Cash Flow Data
Provided by (used in)
Operating activities	$	(166,655	)	$	330,753		$	545,460		$	638,148		$	785,514
Investing activities
Acquisitions		(2,797	)		(301	)		(849,641	)		(161,164	)		(6,401	)
Investment in properties		(111,884	)		(723,829	)		(788,676	)		(816,105	)		(570,670	)
Proceeds from the sale of properties		5,693			261,931			126,265			—			2,750
Other		(13,925	)		1,751			(32,523	)		(16,734	)		4,728
Total investing activities		(122,913	)		(460,448	)		(1,544,575	)		(994,003	)		(569,593	)
Financing activities		(264,022	)		740,737			1,144,921			238,768			(127,241	)
Increase (decrease) in cash		(553,590	)		611,042			145,806			(117,087	)		88,680
Dividends Paid per Common Share	$	—		$	0.26		$	0.48		$	0.33		$	0.07

	June 30,
	2016			2015			2014(3)		2013		2012
	(In thousands)
Balance Sheet Data
Total assets	$	1,025,434		$	4,690,829		$	7,341,497	$	3,505,080	$	3,011,882
Long-term debt including current maturities(2)		2,863,844			4,608,432			3,759,644		1,370,045		1,018,344
Stockholders’ equity (deficit)		(2,654,085	)		(728,722	)		1,734,560		1,367,935		1,286,776
Common shares outstanding		97,824			94,643			93,720		76,486		78,838

(1) The fiscal year 2016 includes $1,525.6 million in gain on early extinguishment of debt resulting from bond repurchases. See Note 8 — “Long-Term Debt” of Notes to our Consolidated Financial Statements in this Form 10-K.

(2) At June 30, 2016, includes $2,764.0 million of long-term debt classified as liabilities subject to compromise on our consolidated balance sheets. See Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources” of Notes to our Consolidated Financial Statements in this Form 10-K.

(3) On June 3, 2014, we completed the EPL Acquisition which significantly increased our scope of operation. See Note 4 — “Acquisitions and Dispositions” of Notes to our Consolidated Financial Statements in this Form 10-K.

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	Year Ended June 30,
Operating Highlights	2016			2015			2014			2013			2012
	(In thousands, except per unit amounts)
Operating revenues
Oil sales	$	546,766		$	1,052,731		$	1,104,208		$	1,067,687		$	1,186,193
Natural gas sales		69,255			117,282			135,883			112,753			88,608
Gain (loss) on derivative financial instruments		90,506			235,439			(86,968	)		(21,508	)		229,809
Total revenues		706,527			1,405,452			1,153,123			1,158,932			1,504,610
Percentage of operating revenues from crude oil prior to gain (loss) on derivative financial instruments		89	%		90	%		89	%		90	%		93	%
Operating expenses
Lease operating expense
Insurance expense		37,958			40,046			31,183			32,737			28,521
Workover and maintenance		58,260			65,562			66,481			65,118			56,413
Direct lease operating expense		249,855			357,927			268,083			239,308			225,881
Total lease operating expense		346,073			463,535			365,747			337,163			310,815
Production taxes		1,442			8,385			5,427			5,246			7,261
Gathering and transportation		55,925			21,144			23,532			24,168			16,371
DD&A		339,516			705,521			414,026			363,791			350,569
Accretion of asset retirement obligations		64,690			50,081			30,183			30,885			39,161
Impairment of oil and natural gas properties		2,813,570			2,421,884			—			—			—
Goodwill impairment		—			329,293			—			—			—
General and administrative		102,736			116,500			96,402			71,598			86,276
Total operating expenses		3,723,952			4,116,343			935,317			832,851			810,453
Operating income (loss)	$	(3,017,425	)	$	(2,710,891	)	$	217,806		$	326,081		$	694,157
Sales volumes per day
Natural gas (MMcf)		92.8			102.7			89.7			88.6			81.5
Crude oil (MBbls)		37.0			41.8			30.1			28.3			30.5
Total (MBOE)		52.5			58.9			45.0			43.1			44.1
Percent of sales volumes from crude oil		71	%		71	%		67	%		66	%		69	%
Average sales price
Oil per Bbl	$	40.36		$	68.99		$	100.59		$	103.48		$	106.17
Natural gas per Mcf		2.04			3.13			4.15			3.48			2.97
Gain (loss) on derivative financial instruments per BOE		4.71			10.95			(5.29	)		(1.37	)		14.24
Total revenues per BOE		36.78			65.36			70.16			73.77			93.21
Operating expenses per BOE
Lease operating expense
Insurance expense		1.98			1.86			1.90			2.08			1.77
Workover and maintenance		3.03			3.05			4.04			4.15			3.49
Direct lease operating expense		13.01			16.64			16.31			15.23			13.99
Total lease operating expense per BOE		18.02			21.55			22.25			21.46			19.25
Production taxes		0.08			0.39			0.33			0.33			0.45
Gathering and transportation		2.91			0.98			1.43			1.54			1.01
DD&A		17.67			32.81			25.19			23.16			21.72
Accretion of asset retirement obligations	$	3.37		$	2.33		$	1.84		$	1.97		$	2.43
Impairment of oil and natural gas properties		146.47			112.63			—			—			—
Goodwill impairment		—			15.31			—			—			—
General and administrative		5.35			5.42			5.87			4.56			5.34
Total operating expenses per BOE		193.87			191.42			56.91			53.02			50.20
Operating income (loss) per BOE	$	(157.09	)	$	(126.06	)	$	13.25		$	20.75		$	43.01

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	Quarter Ended
Operating Highlights	June 30, 2016			March 31, 2016			December 31, 2015			September 30, 2015			June 30, 2015
	(In thousands, except per unit amounts)
Operating revenues
Oil sales	$	133,079		$	95,081		$	139,698		$	178,908		$	225,263
Natural gas sales		14,725			14,430			16,615			23,485			23,908
Gain (loss) on derivative financial instruments		—			6,774			28,302			55,430			(29,711	)
Total revenues		147,804			116,285			184,615			257,823			219,460
Percentage of operating revenues from crude oil prior to gain (loss) on derivative financial instruments		90	%		87	%		89	%		88	%		90	%
Operating expenses
Lease operating expense
Insurance expense		8,269			8,312			10,042			11,335			8,963
Workover and maintenance		17,471			12,105			6,656			22,028			12,243
Direct lease operating expense		55,309			61,627			71,660			61,259			72,268
Total lease operating expense		81,049			82,044			88,358			94,622			93,474
Production taxes		155			221			309			757			1,492
Gathering and transportation		10,014			14,155			16,778			14,978			3,459
DD&A		40,078			53,847			121,567			124,024			183,279
Accretion of asset retirement obligations		18,905			15,057			15,944			14,784			12,358
Impairment of oil and natural gas properties		142,640			340,469			1,425,792			904,669			1,852,268
General and administrative		23,174			28,358			29,015			22,189			25,210
Total operating expenses		316,015			534,151			1,697,763			1,176,023			2,171,540
Operating loss	$	(168,211	)	$	(417,866	)	$	(1,513,148	)	$	(918,200	)	$	(1,952,080	)
Sales volumes per day
Natural gas (MMcf)		86.5			84.8			99.4			100.4			103.2
Crude oil (MBbls)		32.9			35.0			37.9			42.2			42.0
Total (MBOE)		47.3			49.1			54.5			58.9			59.3
Percent of sales volumes from crude oil		70	%		71	%		70	%		72	%		71	%
Average sales price
Oil per Bbl	$	44.44		$	29.86		$	40.05		$	46.11		$	58.87
Natural gas per Mcf		1.87			1.87			1.82			2.54			2.55
Gain (loss) on derivative financial instruments per BOE		—			1.52			5.65			10.23			(5.51	)
Total revenues per BOE		34.32			26.01			36.83			47.57			40.70
Operating expenses per BOE
Lease operating expense
Insurance expense	$	1.92		$	1.86		$	2.00		$	2.09		$	1.66
Workover and maintenance		4.06			2.71			1.33			4.06			2.27
Direct lease operating expense		12.84			13.79			14.30			11.30			13.40
Total lease operating expense per BOE		18.82			18.36			17.63			17.45			17.33
Production taxes		0.04			0.05			0.06			0.14			0.28
Gathering and transportation		2.33			3.17			3.35			2.76			0.64
DD&A		9.31			12.05			24.26			22.88			33.99
Accretion of asset retirement obligations		4.39			3.37			3.18			2.73			2.29
Impairment of oil and natural gas properties		33.12			76.17			284.48			166.91			343.52
General and administrative		5.38			6.34			5.79			4.09			4.68
Total operating expenses per BOE		73.39			119.51			338.75			216.96			402.73
Operating loss per BOE	$	(39.07	)	$	(93.50	)	$	(301.92	)	$	(169.39	)	$	(362.03	)

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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 Item 8, “Financial Statements and Supplementary Data” of 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 Ltd and its wholly-owned subsidiaries (“Energy XXI,” “us,” “we,” “our,” or “the Company”) is an independent oil and natural gas exploration and production company. With our principal operating subsidiary headquartered in Houston, Texas, we have historically engaged in the acquisition, development, operation and exploration of oil and natural gas properties onshore in Louisiana and on the Gulf of Mexico Shelf (“GoM Shelf”). Based on production volume, we are the largest publicly traded independent operator on the GoM Shelf.

We have historically focused on 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.

At June 30, 2016, our total proved reserves were 86.6 MMBOE, of which 77% were oil and 100% were classified as proved developed. We operated or had an interest in 635 gross producing wells on 452,083 net developed acres, including interests in 60 producing fields. We believe operating our assets is a key to our success and approximately 89% 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.

During the second quarter of fiscal year 2015, oil prices began a substantial and rapid decline with continued lower prices throughout fiscal year 2016. Prior to the filing of the Bankruptcy Petitions described below, in response to that decline, we executed a series of financial and operational activities highlighted below.

• Our capital expenditures in fiscal year 2016, including abandonment costs, were reduced to $165 million, as compared to actual capital expenditures in fiscal year 2015 (excluding acquisition activity) of approximately $649 million. Our fiscal year 2016 budget was primarily focused on: (i) recompletion opportunities and lower risk development drilling opportunities in fields where we have had previous success and (ii) eliminating capital commitments on exploration and other activities that do not provide incremental production.

• We reduced field level operating costs, bringing the total amount of direct lease operating costs for fiscal year 2016 down by approximately 30% from fiscal year 2015, and we are continuing to focus on operational and cost efficiencies.

• We suspended dividends on our common stock.

• In March 2015, we closed our private placement of $1,450 million in aggregate principal amount of our Second Lien Notes for net proceeds of $1,355 million, after deducting the initial purchasers’ discount and direct offering costs paid by us. Of the net proceeds, $836 million was used to reduce our outstanding borrowings under our Second Amended and Restated First Lien Credit Agreement (as amended, the “First Lien Credit Agreement” or the “Revolving Credit Facility”) to $150 million, with the remaining amount available for general corporate purposes, including funding a portion of our capital expenditure program for fiscal year 2015 and for fiscal year 2016 as well as funding a portion of our bond repurchases in fiscal year 2016.

• In connection with the issuance of the Second Lien Notes, we proactively amended our Revolving Credit Facility, to, among other things, reduce the total borrowing base availability to $500 million and make certain modifications to the existing financial covenants. On November 30, 2015, the

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lenders under our Revolving Credit Facility (the “Lenders”) reaffirmed the total borrowing base of our Revolving Credit Facility at $500 million and temporarily relaxed the requirements of certain financial covenants. On February 29, 2016, the Thirteenth Amendment and Waiver to our Revolving Credit Facility (the “Thirteenth Amendment”) became effective and on March 14, 2016, the Fourteenth Amendment and Waiver to our Revolving Credit Facility (the “Fourteenth Amendment”) became effective, extending the term of the Thirteenth Amendment until April 15, 2016 and reducing the borrowing base to $327.2 million. Please read “— Liquidity and Capital Resources — Our Indebtedness and Available Credit — Revolving Credit Facility” below for additional information.

• On June 30, 2015, we sold the GIGS for $245 million in cash, plus the assumption of an estimated $12.5 million asset retirement obligation associated with the decommissioning costs of the GIGS. In connection with the closing of the sale of the GIGS, we entered into a triple-net lease with Grand Isle Corridor, LP (“Grand Isle Corridor”) pursuant to which we will continue to operate the GIGS.

• On June 30, 2015, we sold our interest in the East Bay field for cash consideration of $21 million, plus the assumption by the buyer of asset retirement obligations totaling approximately $55.1 million.

• During January 2015, we monetized our existing calendar 2015 ICE Brent three-way collars and Argus-LLS put spreads for total net proceeds of approximately $73.1 million. Additionally, we repositioned our calendar 2015 hedging portfolio by putting on Argus-LLS three-way collars, and we entered into NYMEX WTI collars to hedge a portion of our calendar 2016 production at the then current commodity prices, which provided us some price protection against further decline in oil prices. In March 2016, pursuant to the Fourteenth Amendment we unwound all our outstanding hedging contracts for $50.6 million and used the proceeds therefrom to repay amounts of outstanding loans to EPL under the First Lien Credit Agreement.

• From July 1, 2015 through March 31, 2016, we acquired approximately $1,713.7 million of our unsecured notes in open market transactions at a total cost of approximately $215.9 million (excluding accrued interest) and recorded a gain totaling approximately $1,492.4 million, net of associated debt issuance costs and certain other expenses. These amounts include the $266.6 million purchase of EPL’s 8.25% Senior Notes due February 2018 (the “8.25% Senior Notes”) by EGC in open market transactions, which continue to be held by EGC, and the $471.1 million of EGC’s 9.25% Senior Notes due 2017 (the 9.25% Senior Notes”) repurchased by EGC in open market transactions, which continue to be held by EGC. In addition, certain bondholders holding $37 million in face value of our 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”) requested for conversion. Upon conversion, we recorded a gain of approximately $33.2 million after proportionate adjustment to the related debt issue costs, accrued interest and original debt issue discount. Post-debt repurchases and conversion our total indebtedness owed to third parties was reduced to $2,863.5 million.

As a result of continued decreases in commodity prices and our substantial debt burden, we continued throughout the third quarter of fiscal 2016 to work with our financial and legal advisors to analyze a variety of solutions to reduce our overall financial leverage, while maintaining primary focus on preserving liquidity. As part of this process, we engaged in discussions with certain of our debtholders and other stakeholders to develop and implement a comprehensive plan to restructure our balance sheet. As part of these ongoing discussions, on February 16, 2016, we elected to enter into the 30-day grace period under the terms of the indenture governing EPL’s 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016.

On March 15, 2016, as part of our ongoing discussions with certain of our debtholders, we elected to make the deferred interest payment on the 8.25% Senior Notes, while electing not to make the interest payments due on the Second Lien Notes and on EGC’s 6.875% Senior Notes due 2024 (the “6.875% Senior Notes”), commencing a new 30-day grace period. During the new 30-day grace period, we continued discussions with an ad hoc committee of certain holders of EGC’s Second Lien Notes (the “Second Lien Noteholders”) and a steering committee of the Lenders under our Revolving Credit Facility regarding a potential restructuring. On April 11, 2016, the Debtors entered into a Restructuring Support Agreement (as

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amended, the “Restructuring Support Agreement”) with certain Second Lien Noteholders, providing that the Second Lien Noteholders party thereto will support a restructuring of the Debtors, subject to the terms and conditions of the Restructuring Support Agreement. As contemplated in the Restructuring Support Agreement, the terms of the restructuring of the Debtors are to be effectuated through a joint prearranged plan of reorganization. Pursuant to the Plan (as defined below), we expect to eliminate more than $2,800 million aggregate principal amount of debt and accrued interest held by/due to third-parties, all intercompany debt (including the $325 million intercompany note owed to EGC by EPL, the $266.6 million of the 8.25% Senior Notes purchased by EGC in open market transactions and potentially certain of the Debtors’ intercompany payable balances) as well as the $471.1 million of EGC’s 9.25% Senior Notes repurchased by EGC in open market transactions. As the Plan eliminates substantially all of our prepetition indebtedness other than indebtedness under our Revolving Credit Facility, it will result in a significantly deleveraged capital structure.

Bankruptcy Proceedings and Restructuring Support Agreement

On April 14, 2016 (the “Petition Date”), Energy XXI Ltd, EGC, EPL and certain other subsidiaries of Energy XXI Ltd as listed on Exhibit 21.1 of this Form 10-K (together with the Energy XXI Ltd, the “Debtors”) (excluding Energy XXI GIGS Services, LLC, which leases a subsea pipeline gathering system located in the shallow GoM Shelf and storage and onshore processing facilities on Grand Isle, Louisiana, Energy XXI Insurance Limited through which certain insurance coverage for its operations is obtained by the Company, Energy XXI (US Holdings) Limited, Energy XXI International Limited, Energy XXI Malaysia Limited and Energy XXI M21K, LLC, (together, the “Non-Debtors”)) filed voluntary petitions for reorganization (the petitions collectively, the “Bankruptcy Petitions”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) seeking relief under the provisions of chapter 11 of Title 11 (“Chapter 11”) of the United States Bankruptcy Code (the “Bankruptcy Code”). The Debtors’ Chapter 11 cases (collectively, the “Chapter 11 Cases”) are being jointly administered under the caption “In re: Energy XXI Ltd, et al., Case No. 16-31928.” The Debtors continue to operate their businesses and manage their assets as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Concurrently with the filing of the Bankruptcy Petitions and to streamline the business operations and organization structure following the emergence from Chapter 11 proceedings, Energy XXI Ltd filed a petition to commence an official dissolution under the laws of Bermuda before the Supreme Court of Bermuda (the “Bermuda Proceeding”). On April 15, 2016, John C. McKenna was appointed as provisional liquidator by the Supreme Court of Bermuda. The Bermuda Proceeding is a limited ancillary proceeding under which dissolution of Energy XXI Ltd will be completed following the confirmation of the Plan by the Bankruptcy Court, accordingly, the Bankruptcy Court retains primary jurisdiction over Energy XXI Ltd during the Chapter 11 proceedings. On June 3, 2016, the Bermuda Court granted the Debtors’ request to adjourn the Bermuda Proceeding through November 4, 2016.

On April 26, 2016, the United States Trustee for the Southern District of Texas (the “U.S. Trustee”) appointed an official committee of unsecured creditors (the “UCC”). The UCC is currently composed of the following members: (a) Wilmington Trust, National Association, as successor indenture trustee with respect to certain unsecured notes issued by EGC; (b) Axip Energy Services, LP; (c) Fab-Con, Incorporated; (d) Petroleum Solutions International, LLC; (e) B&J Martin, Inc; (f) Wilmington Savings Fund Society, FSB, as successor indenture trustee with respect to Energy XXI’s 3.0% Senior Convertible Notes; and (g) Delaware Trust Company, as successor indenture trustee with respect to EPL’s 8.25% Senior Notes.

On June 2, 2016, an ad hoc group of equity holders filed a motion seeking to appoint an official committee of equity holders pursuant to section 1102(a)(2) of the Bankruptcy Code (the “Equity Committee Motion”). The Equity Committee Motion was opposed by the Debtors, the UCC, certain Second Lien Noteholders, and Wells Fargo Bank, N.A. as administrative agent (the “First Lien Agent”) under our Revolving Credit Facility, all of whom filed objections to the Equity Committee Motion. However, at an emergency hearing on the Equity Committee Motion on June 15, 2016, the Bankruptcy Court ruled that it would be appropriate to appoint an equity committee, subject to certain limitations. On June 17, 2016, the U.S. Trustee appointed an official committee of equity security holders (the “Equity Committee”).

On July 15, 2016, the Bankruptcy Court entered the Order (A) Approving the Disclosure Statement and the Form and Manner of Service Related Thereto, (B) Setting Dates for the Objections Deadline and Hearing

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Related to Confirmation of the Plan, and (C) Granting Related Relief [Docket No. 805], approving the adequacy of the Third Amended Disclosure Statement for the Debtors’ Proposed Joint Chapter 11 Plan of Reorganization [Docket No. 809] (the “Disclosure Statement”) and related solicitation materials, thereby authorizing the Debtors to solicit votes to accept or reject the Debtors’ Proposed Joint Chapter 11 Plan of Reorganization [Docket No. 810] from applicable creditor constituencies.

On September 8, 2016, a meeting (the “September 8 Meeting”) occurred between certain representatives of the Debtors, certain Second Lien Noteholders, the UCC, certain holders of unsecured indebtedness issued by EGC (the “Ad Hoc EGC Group”) and certain holders of unsecured indebtedness issued by EPL (the “Ad Hoc EPL Group”), during which the Second Lien Noteholders made an offer to the Debtors, the UCC, the Ad Hoc EGC Group and advisors to the Ad Hoc EPL Group to modify certain terms of the Debtor’s July 15, 2016 proposed plan (the “September 8 Second Lien Offer”). The UCC and the Ad Hoc EGC Group did not accept the September 8 Second Lien Offer, submit a counter-offer or enter into any negotiations with the Debtors or the Second Lien Noteholders following the receipt of the September 8 Second Lien Offer during the September 8 meeting. However, on September 12, 2016, the Debtors received a proposal for an alternative chapter 11 plan of reorganization from the Ad Hoc EGC Group and the Ad Hoc EPL Group, which the Debtors are in the process of reviewing with their advisors.

Following subsequent negotiations between the Debtors and the Second Lien Noteholders, on September 13, 2016, the Debtors and the Second Lien Noteholders entered into the Fifth Amendment to the Restructuring Support Agreement (the “Fifth RSA Amendment”), which provided, among other things, that the Debtors file an amended Plan to reflect the terms of the Fifth RSA Amendment. The boards of directors of the Company, EGC and EPL, including all independent directors, approved the entry into the Fifth RSA Amendment and the term sheet attached thereto. Subject to approval by the Bankruptcy Court, the terms of the restructuring of the Debtors, as contemplated in the Fifth RSA Amendment, were included in the Debtors’ Amended Proposed Joint Chapter 11 Plan of Reorganization [Docket No. 1307], filed September 14, 2016 (as may be amended, modified, or supplemented from time to time, the “Plan”).

On September 16, 2016, the Debtors filed an initial form of supplement (the “DS Supplement”) to the Disclosure Statement, which summarized the modifications to the Plan contemplated by the Fifth RSA Amendment. The Plan as amended now supersedes the September 8 Second Lien Offer. The Debtors sought approval of the adequacy of the DS Supplement and related solicitation materials at a hearing held before the Bankruptcy Court on September 22, 2016, following which the Bankruptcy Court approved the DS Supplement in its Order (A) Approving the Adequacy of the Supplement to the Debtors’ Third Amended Disclosure Statement Setting Forth Modifications to the Debtors’ Proposed Joint Chapter 11 Plan of Reorganization and the Continued Solicitation of the Plan and (B) Granting Related Relief [Docket No. 1416] on September 25, 2016. The Debtors will distribute the DS Supplement and related solicitation materials to creditors entitled to vote on the Plan to enable such creditors to vote on the Plan changes.

In an effort to consensually resolve outstanding disputes among the parties in interest, representatives for the Debtors, the First Lien Agent, the Second Lien Noteholders, the UCC and its members, the Equity Committee, the Ad Hoc EGC Group, and the Ad Hoc EPL Group have agreed to participate in a confidential and non-binding mediation process, as discussed on the record at a hearing before the Bankruptcy Court on September 13, 2016. On September 16, 2016, the Bankruptcy Court appointed Judge Leif Clark as the mediator. Mediation is scheduled to commence on September 28, 2016.

The hearing to consider confirmation of the Plan is currently set for October 17, 2016, but may change depending upon the outcome of, among other things, mediation and other developments in the Chapter 11 Cases.

As amended, the Restructuring Support Agreement provides, among other things, that:

• The dissolution of Energy XXI Ltd will be completed under the laws of Bermuda following the confirmation of the Plan by the Bankruptcy Court, and, given that it is unlikely to have assets available for distribution, existing equity holders will receive no distribution in respect of that equity in that dissolution.

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• The Debtors, on behalf of the holders of claims (the “First Lien Claims”) arising on account of the Company’s Revolving Credit Facility and subject to further negotiations with the Lenders under the Revolving Credit Facility, will use their best efforts to ensure that at emergence from Chapter 11, the amount drawn under the Revolving Credit Facility either (i) remains outstanding or (ii) is refinanced with a new facility with terms acceptable to the Second Lien Noteholders party to the Restructuring Support Agreement (the “Restructuring Support Parties”) who hold, in aggregate, at least 66.6% in principal amount of the Second Lien Notes Claims (as defined below) held by the Restructuring Support Parties (the “Majority Restructuring Support Parties”); provided, however that (a) $227.8 million of letters of credit usage remains outstanding and (b) other terms, including a borrowing base redetermination holiday, are acceptable to the Debtors and the Majority Restructuring Support Parties. If the Debtors are unable to obtain the foregoing treatment of the First Lien Claims, then the Debtors will use their best efforts to obtain treatment acceptable to the Debtors and the Majority Restructuring Support Parties.

• Holders of claims against any Debtor (other than an administrative claim or a secured tax claim) entitled to priority in right of payment under section 507(a) of the Bankruptcy Code, to the extent such claim has not already been paid during the Chapter 11 Cases will receive either: (i) payment in full in equal to the full allowed amount of such claim or (ii) such other treatment as may otherwise be agreed to by such holder, the Debtors, and the Majority Restructuring Support Parties.

• Holders of secured claims (other than a priority tax claim, First Lien Claim, or Second Lien Notes Claim) will receive, at the Debtors’ election and with the consent of the Majority Restructuring Support Parties, either: (i) cash equal to the full allowed amount of such claim, (ii) reinstatement of such holder’s claim, (iii) the return or abandonment of the collateral securing such claim to such holder, or (iv) such other treatment as may otherwise be agreed to by such holder, the Debtors, and the Majority Restructuring Support Parties.

• Holders of claims relating to the Second Lien Notes (the “Second Lien Notes Claims”) will receive their pro rata share of (i) 87.8% of common stock (the “New Equity”) in the reorganized company (the “New Entity”) on account of such Second Lien Notes Claims, subject to dilution from the issuance of New Equity in connection with the long-term management incentive plan for the reorganized Debtors (the “Management Incentive Plan”) and (ii) the New Equity allocated to the Second Lien Notes Claims in connection with the EGC Intercompany Note Trust (as defined below), if applicable, and subject to dilution by the Management Incentive Plan;

• Holders of claims relating to the unsecured EGC notes (the “EGC Unsecured Notes Claims”) will receive their pro rata share of (i) 0.4% of the New Equity, subject to dilution from the Management Incentive Plan and (ii) the New Equity allocated to the EGC Unsecured Notes Claims in connection with the EGC Intercompany Note Trust, if applicable, and subject to dilution by the Management Incentive Plan;

• Holder of claims relating to the unsecured EPL notes (the “EPL Unsecured Notes Claims”) will receive their pro rata share of the New Equity allocated to the EPL Unsecured Notes Claims in connection with the EGC Intercompany Note Trust, if applicable;

• Holders of claims relating to the Company’s 3.0% Senior Convertible Notes will receive their pro rata share of 0.2% of the New Equity, subject to dilution from the Management Incentive Plan;

• As of the date that the Debtors must consummate the transactions contemplated by the Plan (the date of such consummation, the “Effective Date”), 11.6% of the New Equity will be deposited into a trust (the “EGC Intercompany Note Trust”) and to be distributed among the Second Lien Notes Claims, the EGC Unsecured Notes Claims and the EPL Unsecured Notes Claims pursuant to a final order entered by the Bankruptcy Court resolving any causes of action, as well as all applicable defenses and counterclaims, challenging: (a) the validity and enforceability of that certain promissory note in the principal amount of $325.0 million between EPL, as the maker, and EGC, as the payee, (the “EGC Intercompany Note”) on the grounds of: preference; recharacterization; equitable subordination; and/or fraudulent transfer; and (b) the validity and enforceability of the

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intercompany payables between EGC and EPL other than the EGC Intercompany Note; provided however, that the distribution under the EGC Intercompany Note Trust to the holders of Second Lien Notes Claims (i) will not exceed 93.2%, (ii) the distribution to the holders of EGC Unsecured Notes Claims will not exceed 6.6%, (iii) the distribution to the holders of EPL Unsecured Notes Claims will not exceed 11.6% and (iv) $500,000 cash will be deposited in equal amounts in two separate, non-interest bearing escrow accounts to fund the respective fees and expenses of the advisors of the trustee representing EGC and the trustee representing EPL in connection with the EGC Intercompany Note Trust;

• The Management Incentive Plan will be capped at 5%;

• John D. Schiller, Jr. will continue as the New Entity’s Chief Executive Officer and a member of its Board of Directors; and

• The Debtors will negotiate the terms and conditions of an amended and restated employment agreement with Mr. Schiller as Chief Executive Officer of the reorganized company, which terms and conditions shall be subject to the prior written consent of the Majority Restructuring Support Parties.

Milestones

As amended, the Restructuring Support Agreement also contains the following proposed milestones (the “Milestones”) for progress in the Chapter 11 proceedings:

• no later than October 7, 2016, the Bankruptcy Court will have commenced the hearing to consider confirmation of the Plan (the “Confirmation Hearing”);

• no later than October 13, 2016, the Bankruptcy Court will have entered an order authorizing the assumption of the Restructuring Support Agreement;

• no later than October 13, 2016, the Bankruptcy Court will have entered the confirmation order with respect to the Plan; and

• no later than October 27, 2016, the Debtors shall consummate the transactions contemplated by the Plan, it being understood that the satisfaction of the conditions precedent to the Effective Date (as set forth in the Plan) shall be conditions precedent to the occurrence of the Effective Date.

The Confirmation Hearing is currently set for October 17, 2016, but may change depending upon the outcome of, among other things, mediation and other developments in the Chapter 11 Cases. The Debtors anticipate entering into a further Restructuring Support Agreement amendment to modify the Milestones to reflect this new timeline in the near term.

The Majority Restructuring Support Parties have the right, but not the obligation, to terminate their obligations under the Restructuring Support Agreement upon the failure of the Debtors to meet any of the Milestones set forth above unless (i) such failure is the direct result of any act, omission, or delay on the part of any Restructuring Support Party in violation of its obligations under the Restructuring Support Agreement or (ii) such Milestone is extended with the express prior written consent of the Majority Restructuring Support Parties.

Reorganization Process

On the Petition Date, the Bankruptcy Court issued certain interim and final orders with respect to the Debtors’ first-day motions and other operating motions that allow the Debtors to operate their businesses in the ordinary course. The first-day motions provided for, among other things, the payment of certain pre-petition employee and retiree expenses and benefits, the use of the Debtors’ existing cash management system, the payment of certain pre-petition amounts to certain critical vendors, the ability to pay certain pre-petition taxes and regulatory fees, and the payment of certain pre-petition claims owed on account of insurance policies and programs.

Subject to certain exceptions under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other

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actions against the Debtors or their property to recover, collect or secure a pre-petition claim. Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’ property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay under Section 362 of the Bankruptcy Code.

Under Section 365 and other relevant sections of the Bankruptcy Code, the Debtors’ may assume, assume and assign, or reject certain executory contracts and unexpired leases, including leases of real property and equipment, subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach. On July 8, 2016, the Debtors filed a motion for an order to extend time to assume or reject unexpired leases of nonresidential real property from August 15, 2016 through and including November 14 (the “Motion to Extend Time to Assume or Reject Unexpired Leases”). On July 27, 2016 the Bankruptcy Court entered an order approving the Motion to Extend Time to Assume or Reject Unexpired Leases. On July 26, 2016, the Debtors filed a motion to reject executory contracts, for certain contracts contained therein. On August 23, 2016, the Bankruptcy Court granted the Debtors’ motion in the Order (A) Authorizing the Debtors to Reject Certain Executory Contracts Effective Nunc Pro Tunc to July 26, 2016, and (B) Granting Related Relief [Docket No. 1133].

A Chapter 11 plan (including the Plan) determines the rights and satisfaction of claims of various creditors and security holders and is subject to the ultimate outcome of negotiations and the Bankruptcy Court’s decisions through the date on which a Chapter 11 plan (including the Plan) is confirmed. The Plan currently provides mechanisms for settlement of the Debtors’ pre-petition obligations, changes to certain operational cost drivers, treatment of our existing equity holders, potential income tax liabilities and certain corporate governance and administrative matters pertaining to the reorganized New Entity. The Plan remains subject to revision based upon discussions with the Debtors’ creditors, including the Lenders under the Revolving Credit Facility and holders of the EGC Unsecured Notes Claims, holders of EPL Unsecured Notes Claims, and holders of claims relating to Energy XXI’s 3.0% Senior Convertible Notes, and other interested parties, and thereafter in response to any Plan objections and the requirements of the Bankruptcy Code or the Bankruptcy Court. There can be no assurance that the Debtors will be able to secure Bankruptcy Court approval of the Plan or any other Chapter 11 plan or that the Plan or any other Chapter 11 plan will be accepted by the classes of creditors entitled to vote thereon.

Under the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before stockholders are entitled to receive any distribution or retain any property under a Chapter 11 plan (including the Plan). The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation of a Chapter 11 plan (including the Plan). No assurance can be given as to what values, if any, will be ascribed to each of these constituencies or what types or amounts of distributions, if any, they would receive. A Chapter 11 plan (including the Plan) could result in holders of certain liabilities and/or securities, including common stock, receiving no distribution on account of their interests. Because of such possibilities, there is significant uncertainty regarding the value of our liabilities and securities, including our common stock. At this time, there is no assurance we will be able to restructure as a going concern or successfully propose or implement a Chapter 11 plan (including the Plan).

In accordance with the Milestones, we filed the Disclosure Statement, Plan, a motion seeking, among other things, (A) approval of the Disclosure Statement, (B) approval of procedures for soliciting, receiving, and tabulating votes on the Plan and for filing objections to the Plan, and (C) to schedule the Confirmation Hearing on May 20, 2016. Subsequently, we filed amended versions of the Disclosure Statement and Plan on June 14, 2016, July 13, 2016, September 14, 2016 and again on September 23, 2016. The amendments reflected, among other things, substantial additional disclosures requested by certain creditor constituencies. The amendments also reflected changes to the proposed treatment of certain classes under the Plan made in conjunction with or as a result of amendments to the Restructuring Support Agreement.

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The Bankruptcy Court entered an order approving the Disclosure Statement with respect to the Plan on July 15, 2016, and we filed the solicitation version of the Disclosure Statement on July 18, 2016. Under the Bankruptcy Code, only holders of claims or interests in “impaired” classes, as defined under section 1124 of the Bankruptcy Code, are entitled to vote on a plan. Ballots to vote to accept or reject the plan were distributed to creditors entitled to vote on the plan between July 22, 2016 and July 25, 2016. On September 22, 2016, the Bankruptcy Court held a hearing to consider the adequacy of the DS Supplement reflecting certain changes to the Plan. The Bankruptcy Court approved the DS Supplement on September 25, 2016. The Debtors will distribute the DS Supplement and related solicitation materials to creditors entitled to vote on the Plan, to enable creditors to vote on the Plan as amended. The deadline to submit a vote to accept or reject the Plan is October 13, 2016 at 5:00 P.M., central time. The hearing to consider confirmation of the Plan is scheduled for October 17, 2016 before the Bankruptcy Court.

Even if our Plan meets other requirements under the Bankruptcy Code, creditors may not vote in favor of our Plan, and certain parties in interest may file objections to the Plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Further, even if no objections are filed and the requisite acceptances of our Plan are received from creditors entitled to vote on the Plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Plan.

For periods subsequent to filing the Bankruptcy Petitions, we have applied the Financial Accounting Standards Board Accounting Standards Codification (“ASC”) 852, Reorganizations, in preparing the consolidated financial statements. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, the pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

Going Concern Matters

The consolidated financial statements included in this Form 10-K have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. However, the Chapter 11 Cases and sustained depressed commodity prices raise substantial doubt about our ability to continue as a going concern.

The consolidated financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern.

Liquidity After Chapter 11 Proceedings

Upon our emergence from the Chapter 11 Cases, we are required to have under the new exit financing (the “Exit Facility”) liquidity of at least $90 million (the “Minimum Cash Balance”) per the Exit Facility Term Sheet with the Lenders under our First Lien Credit Agreement attached to the Plan as Exhibit 1 (the “Exit Facility Term Sheet”). While we expect the Exit Facility and Minimum Cash Balance to be available under the Plan, we may not be able to access adequate funding in the future as there will be no remaining available borrowing capacity contemplated under the Exit Facility, and there is no certainty that any new capacity will be created or that the Exit Facility may be refinanced on economically advantageous terms, and the Minimum Cash Balance and anticipated cash flow from operating activities will be adequate to execute our corporate strategies may not be sufficient to otherwise fund our operations. Additionally, there are certain risks and uncertainties that could negatively impact our results of operations and financial condition. Sustained declines in prices for commodities may also put downward pressure on cash provided from our operations.

Exit Facility

As contemplated by the Exit Facility Term Sheet, which is subject to change and to be considered in connection with Plan confirmation, we anticipate that the New Entity will enter into new exit financing (the

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“Exit Facility”) comprised of the following tranches: (i) conversion of the remaining drawn amount, net of related restricted cash, of approximately $69 million plus accrued default interest into a new term loan (the “Exit Term Loan”) with the New Entity and (ii) the conversion of the former EGC tranche of the Revolving Credit Facility into a new EGC sub-facility (the “EGC Facility”). The Exit Term Loan will have a maturity of three years with an annual interest rate of LIBOR plus 4.5%, payable monthly. The EGC Facility will have a maturity of three years with an annual interest rate of 4.5%, payable on a schedule consistent with the Revolving Credit Facility. Existing letters of credit may be renewed or replaced (in each case, in an outstanding amount not to exceed the outstanding amount of the existing letter of credit). Availability under the Exit Facility will be permanently reduced by one-half of the amount of any reduction resulting from replacement or cancellation of an outstanding letter of credit. Any amount of cancellation or reduction that does not permanently reduce capacity will be available for the New Entity to fund new liquidity (the “New Funded Debt”). Such New Funded Debt in excess of $25 million will be subject to borrowing base redetermination. Pursuant to the Exit Facility, the New Entity and its subsidiaries will be subject to certain financial maintenance covenants and, in the case of the Exit Term Loan, amortization covenants.

Known Trends and Uncertainties

Commodity Price Volatility and Impact on our Results of Operations.  Prices for oil and natural gas historically have been volatile and are expected to continue to be volatile. Oil and natural gas prices declined significantly during fiscal year 2015 and the decline continued with lower prices throughout fiscal year 2016. The posted price per barrel for West Texas intermediate light sweet crude oil, or WTI, for the period from October 1, 2014 to June 30, 2016 ranged from a high of $91.01 to a low of $26.21, a decrease of 71.2%, and the NYMEX natural gas price per MMBtu for the period October 1, 2014 to June 30, 2016 ranged from a high of $4.49 to a low of $1.64, a decrease of 63.5%. As of June 30, 2016, the spot market price for WTI was $48.33. Oil prices remain depressed in 2016, with the price of WTI crude oil per barrel dropping below $27.00 in February 2016 for the first time in twelve years. Although oil prices have rebounded above $40.00 per barrel through September 2016, there is still significant volatility in commodity prices and these prices are still significantly lower than the industry has experienced in recent years. The recent declines in oil and natural gas prices have adversely affected our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce.

Exploration and Production (“E&P”) Bankruptcies.  In the United States, several E&P companies with substantial debt filed for bankruptcy protection between July 2014 and September 2016. With the continued market instability, numerous E&P companies have been forced to stop drilling new wells — the core of an E&P company’s business — and cut capital expenditures, as it is not economically feasible to undertake capital intensive projects at current prices. Others have been forced to sell off assets at severe discounts, or even stop operations altogether. The Company along with the independent directors at EGC and EPL has determined that commencing Chapter 11 cases to implement the restructuring contemplated by the Restructuring Support Agreement will maximize value for its stakeholders.

Reserve Quantities.  A prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserve portfolio. At June 30, 2016, our total proved reserves were 86.6 MMBOE. The unweighted arithmetic average first-day-of-the-month prices adjusted for differentials used to determine our reserves as of June 30, 2016 were $42.69 per barrel of oil, $18.38 per barrel for NGLs and $1.94 per MMBtu for natural gas. The Company’s proved reserves declined significantly compared to prior year and may decline in future years.

Due to the depressed commodity prices and our lack of capital resources to develop our properties, all of our proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result, we removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category on December 31, 2015 are still economic at current prices, but were reclassified to the contingent resource category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $336.5 million as being uneconomical and transferred such amounts to the full cost pool, subject to amortization.

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Ceiling Test Write-down.  During the year ended June 30, 2016, we recognized write-downs of our oil and natural gas properties totaling $2,813.6 million. The write-downs did not impact our cash flows from operating activities but substantially contributed to our net loss for the period and increased our stockholders’ deficit. Further ceiling test write-downs will be required if oil and natural gas prices remain low or decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and natural gas properties otherwise exceeds the present value of estimated future net cash flows.

Decreasing Service Costs.  We have also seen a significant and continuing reduction in rig rates and drilling costs, which should allow us to spend less capital drilling our development wells than in prior periods.

BOEM Supplemental Financial Assurance and/or Bonding Requirements.  As of June 30, 2016, we had $388.0 million of performance bonds outstanding and $225 million in letters of credit issued to a third party relating to assets in the Gulf of Mexico. We are a lessee and operator of oil and natural gas leases on the federal OCS and our operations on these leases in the Gulf of Mexico are subject to regulation by the BSEE and the BOEM. These leases require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws. Consequently, as of June 30, 2016, we have submitted approximately $226.6 million of our performance bonds in the form of general or supplemental bonds issued to the BOEM that may be accessed and used by the BOEM to assure our commitment to comply with our lease obligations, including decommissioning obligations. We also maintain approximately $161.4 million in performance bonds issued not to the BOEM but rather to predecessor third party assignors, including certain state regulatory bodies, of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities.

In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for exemption from certain supplemental bonding requirements for potential offshore decommissioning obligations and that certain of our subsidiaries must provide approximately $1,000 million in supplemental bonding or other financial assurance for our offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In October 2015, we received information from the BOEM that we could receive additional demands of supplemental bonding or other financial assurance for amounts in addition to the $1,000 million initially sought by the BOEM in April 2015, primarily relating to certain leases in which we have a legal interest that were no longer exempt from supplemental bonding as a result of co-lessees losing their exemptions. Since April 2015, we have had a series of discussions and exchanges of information with the BOEM regarding our submittal of additional supplemental bonding or other financial assurance with respect to offshore oil and gas interests that has resulted in, among other things: (i) our submittal of $150 million and $21.1 million in supplemental bonds to the BOEM in June 2015 and December 2015, respectively (which bond amounts are reflected in the $226.6 million in general and/or supplemental bonds discussed above); (ii) our selling of the East Bay field on June 30, 2015 that served to reduce by $178 million the $1,000 million of supplemental bonding or other financial assurance required by the BOEM in April 2015; and (iii) the BOEM’s agreement to, and execution of, the Long-Term Plan on February 25, 2016 that is intended to address the supplemental bonding and other financial assurance concerns expressed to us by the BOEM in April and October 2015.

As required by our Long-Term Plan, we must perform, among other things, the following activities (numbers in parentheses correspond to numbers in the Long-Term Plan): (3) use our best commercial efforts to have the BOEM included as an additional obligee under our third-party bonds by July 1, 2016; (4) provide additional financial assurance as may be required under the applicable BOEM requirements with respect to any of our pending or future plans or activities for offshore leasing, exploration or development, including any permitting or assignment associated with such plans or activities (but excluding certain internal restructuring assignments or transfers between us and our subsidiaries or our affiliates, EPL and M21K); (5) pursue a multi-obligee security acceptable to the BOEM with respect to letters of credit covering certain properties acquired by us by July 1, 2016, or submit to the BOEM a plan for providing to the BOEM other satisfactory forms of financial assurance with respect those properties covered by such letters of credit; (6) with respect to certain of our operated properties with active non-waived co-lessees, make diligent efforts to negotiate with our co-lessees to achieve full financial assurance for certain of such offshore facility interests by submitting a

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plan for these properties by July 1, 2016; (7) work with the BOEM and BSEE in reconciling data discrepancies identified by us within the time allotted by the Long-Term Plan for posting the bonds on the affected properties; (8) work with BOEM and our insurers to potentially receive credit for our energy insurance package; and (9) work with the third-party operators of our non-operated interests to address our proportionate share of any supplemental bond demands on these non-operated properties. A primary belief that we held in the development of the Long-Term Plan was that a substantial portion of the financial assurance that could be sought by the BOEM based on the information received in October 2015 may relate to circumstances that could eventually be removed from our responsibility (in terms of providing added bonding or assurance) including, for example, lease interests of co-lessees, leases that have since been divested by us, and leases where we are not the permitted operator and no drilling of wells has occurred. Our expectation is that most, if not all, of our co-lessees with the remaining working interest in such lease interests will provide their share of the bonding.

Pursuant to the Restructuring Support Agreement entered into on April 11, 2016, it is anticipated that we will continue to perform our obligations under the Long-Term Plan during the pendency of the Chapter 11 Cases and in connection with the consummation of our restructuring. On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with the third party, it was agreed that subsequent to the Company’s emergence from the Chapter 11 Cases, the letters of credit issued in favor of the third party would be reduced to $200 million from the existing amount of $225 million. We submitted an amended and supplemental plan to the BOEM on June 28, 2016 pursuant to which we will continue to pursue, among other things, certain of the tasks described above in a manner as further set forth in the amended and supplemental long term plan. We are currently awaiting their further response.

On July 14, 2016, the BOEM issued a new NTL regarding the need for additional security to satisfy decommissioning obligations and eliminating previous exemptions from the posting of financial assurances. Notwithstanding the BOEM’s July 14, 2016 NTL, the BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of compliance with our existing supplemental bonding requirements, including the obligations imposed upon us under the Long-Term Plan and the July 14, 2016 NTL, any other future BOEM directives, or any other changes to the BOEM’s rules applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, although we currently have $49.3 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors, we may be required to provide additional cash collateral in the future to support the issuance of such bonds or other financial security. While we are currently in compliance, we can provide no future assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient operating cash flows to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may have any of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties and one or more of such actions could have a material effect on our business, prospects, results of operations, financial condition, and liquidity.

Oil Spill Response Plan.  We maintain a Regional Oil Spill Response Plan (the “OSRP”) that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are approved by the BSEE. The OSRP is reviewed annually and updated as necessary, which updates also require BSEE approval. The OSRP specifications are consistent with the requirements set forth by the BSEE. Additionally, the OSRP is tested and drills are conducted annually at all levels of the Company.

We have contracted with a spill response management consultant to provide management expertise, personnel and equipment, under our supervision, in the event of an incident requiring a coordinated response. Additionally, we are a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico that has the appropriate equipment, including aircraft dispersant capabilities through its contract with Airborne Support Inc. and access to appropriate personnel to simultaneously respond to multiple spills. In the event of a spill, CGA mobilizes appropriate equipment and personnel to CGA members.

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Hurricanes.  Since the majority of our production originates in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. 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.

Acquisition and Dispositions

Sale of the Grand Isle Gathering System

On June 30, 2015, we sold certain real and personal property constituting a subsea pipeline gathering system located in the shallow GoM shelf and storage and onshore processing facilities on Grand Isle, Louisiana (altogether, and as previously defined, the “GIGS”) to Grand Isle Corridor, a wholly-owned subsidiary of CorEnergy Infrastructure Trust, Inc. for cash consideration of $245 million, plus the assumption of an estimated $12.5 million asset retirement obligation associated with the decommissioning costs of the GIGS. 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 $248.9 million.

Additionally on June 30, 2015, in connection with the closing of the sale of the GIGS, one of our wholly-owned subsidiaries (the “Tenant”) entered into a triple-net lease (the “GIGS Lease”) with Grand Isle Corridor pursuant to which we continue to operate the GIGS. The primary term of the GIGS Lease is 11 years from the closing of the sale, with one renewal option, which will be the lesser of nine years or 75% of the expected remaining useful life of the GIGS. The operating lease utilizes a minimum rent plus a variable rent structure, which is linked to the oil revenues we realize from the GIGS above a predetermined oil revenue threshold. During the initial term, we will make fixed minimum monthly rental payments, which vary over the term of the lease. The aggregate annual minimum cash monthly payments for the first twelve months of the GIGS Lease total $31.5 million, and such payment amounts average $40.5 million per year over the life of the lease. Under the terms of the GIGS Lease, we retain any revenues generated from transporting third party volumes.

Under the terms of the GIGS Lease, we control the operation, maintenance, management and regulatory compliance associated with the GIGS, and we are responsible for, among other matters, maintaining the system in good operating condition, paying all utilities, insuring the assets, repairing the system in the event of any casualty loss, paying property and similar taxes associated with the system, and ensuring compliance with all environmental and other regulatory laws, rules and regulations. The GIGS Lease also imposes certain obligations on Grand Isle Corridor, including confidentiality of information and keeping the GIGS free of certain liens. In addition, we have, under certain circumstances, a right of first refusal during the term of the GIGS Lease and for two years thereafter to match any proposed transfer by Grand Isle Corridor of its interest as lessor under the GIGS Lease or its interest in the GIGS.

Under the GIGS Lease, an event of default would be triggered by the Tenant upon (i) the filing by either the Tenant or the Company of a Bankruptcy Petition or (ii) the failure of either the Tenant or the Company to make any payment of principal or interest with respect to certain material debt of the Tenant or the Company, as guarantor, after giving effect to any applicable cure period or the failure to perform under an agreement or instrument relating to such material debt (collectively, the “Specified Defaults”). Although the Tenant did not file a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code, the Debtors’ filing of the Bankruptcy Petitions and failure to comply with our material debt instruments, would, among other things, allow Grand Isle Corridor to terminate the Lease.

As a result, the Tenant and Grand Isle Corridor entered into a Waiver to Lease, dated as of April 13, 2016 (the “Waiver”), whereby Grand Isle Corridor waived its right to exercise its remedies set forth under the GIGS Lease in the event of the Specified Defaults except its ability to exercise observer rights as detailed in the GIGS Lease. The Waiver will terminate if any of the following events occur: (i) a dismissal of the Bankruptcy Petitions, (ii) conversion of the pending case from a Chapter 11 bankruptcy to a chapter 7 bankruptcy case or other liquidation proceeding, (iii) relief from the automatic stay or other relief which allows the creditors of the material debt to take action to enforce such material debt against the Company or its property or (iv) a Tenant Event of Default (as defined in the GIGS Lease) under the GIGS Lease other than arising out of the Specified Defaults expressly waived.

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Sale of interests in the East Bay field

On June 30, 2015, we sold our interest in the East Bay field to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC, for cash consideration of $21 million plus the assumption of asset retirement obligations estimated at $55.1 million. The cash consideration was payable in two installments with $5 million received at closing and the remainder in fiscal year 2016. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. Revenues and expenses related to the field were included in our results of operations through June 30, 2015. 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 $68.9 million. We had acquired our interest in the East Bay field in the EPL Acquisition on June 3, 2014.

Subsequent to June 30, 2015, post closing adjustments reduced the total cash consideration to $20.3 million and the maximum receivable under the overriding royalty interest to $6.2 million.

Purchase of interests in M21K, LLC

On August 11, 2015, we acquired all of the remaining equity interests of M21K, LLC (“M21K”) for consideration consisting of the assumption of all obligations and liabilities of M21K including approximately $25.2 million associated with M21K’s first lien credit facility, which was required to be paid at closing. Prior to this transaction, we had owned a 20% interest in M21K through our investment in EXXI M21K, LLC. See Note 4 — “Acquisitions and Dispositions” and Note 7 — “Equity Method Investments” of Notes to our Consolidated Financial Statements in this Form 10-K for more information regarding these transactions.

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 $2,500 million, including the assumption of EPL’s debt. The aggregate consideration received by EPL shareholders was paid 65% in cash and 35% in Energy XXI common shares and consisted of approximately $1,010 million 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%. The EPL Acquisition significantly increased our scope of operation. The EPL assets are located on the GoM Shelf and have been operationally integrated into our existing portfolio on the GoM Shelf.

Please also see Note 4 — “Acquisitions and Dispositions” of Notes to our Consolidated Financial Statements in this Form 10-K for more information regarding these above transactions.

Results of Operations

Year Ended June 30, 2016 Compared to the Year Ended June 30, 2015

Our consolidated net loss attributable to common stockholders for the year ended June 30, 2016 was $1,927.1 million or $20.11 diluted net loss per common share (“per share”) as compared to $2,445.3 million or $25.97 per share for the year ended June 30, 2015. The decrease in the loss was primarily due to the gain on the early extinguishment of debt, partially offset by lower revenues due to lower oil and natural gas sales prices, lower gain on derivative financial instruments and lower oil and natural gas properties impairment. In addition, DD&A and lease operating expenses were lower in the year ended June 30, 2016 compared to the year ended June 30, 2015. The year ended June 30, 2015 also included impairment of goodwill.

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Revenue Variances

	Year Ended June 30,				Decrease			Percent Decrease
	2016		2015
			(In thousands)
Oil	$	546,766	$	1,052,731	$	(505,965	)		(48.1	)%
Natural gas		69,255		117,282		(48,027	)		(41.0	)%
Gain on derivative financial instruments		90,506		235,439		(144,933	)		(61.6	)%
Total Revenues	$	706,527	$	1,405,452	$	(698,925	)		(49.7	)%

Revenues

Our consolidated revenues decreased $698.9 million for the year ended June 30, 2016 as compared to the year ended June 30, 2015. Lower revenues were primarily due to lower commodity sales prices and lower gain on derivative financial instruments as well as declines in sales volumes. Revenue variances related to commodity prices, sales volumes and hedging activities are presented in the following table and described below.

Price and Volume Variances

	Year Ended June 30,						Decrease			Percent Decrease			Revenue Decrease
	2016			2015
													(In thousands)
Price Variance
Oil sales prices (per Bbl)(1)	$	40.36		$	68.99		$	(28.63	)		(41.5	)%	$	(436,868	)
Natural gas sales prices (per Mcf)(1)		2.04			3.13			(1.09	)		(34.8	)%		(40,882	)
Gain on derivative financial instruments (per BOE)		4.71			10.95			(6.24	)		(57.0	)%		(144,933	)
Total price variance														(622,683	)
Volume Variance
Oil sales volumes (MBbls)		13,547			15,259			(1,712	)		(11.2	)%		(69,097	)
Natural gas sales volumes (MMcf)		33,973			37,472			(3,499	)		(9.3	)%		(7,145	)
BOE sales volumes (MBOE)		19,209			21,504			(2,295	)		(10.7	)%
Percent of BOE from oil		71	%		71	%
Total volume variance														(76,242	)
Total price and volume variance													$	(698,925	)

(1) Commodity prices exclude the impact of derivative financial instruments.

Price Variances

Commodity prices are one of the key drivers of our earnings and net operating cash flow. Lower commodity prices decreased revenues by $622.7 million in the year ended June 30, 2016 as compared to the year ended June 30, 2015. Average oil prices decreased $28.63 per barrel in the year ended June 30, 2016, resulting in lower revenues of $436.9 million. Average natural gas prices decreased $1.09 per Mcf during the year ended June 30, 2016, resulting in lower revenues of $40.9 million. For fiscal 2016, our hedging activities resulted in a gain on derivative activities of $4.71 per BOE compared to $10.95 per BOE for the prior fiscal year, resulting in lower revenues of $144.9 million. The gain on derivatives for the year ended June 30, 2016 reflects a gain on settlements and monetization of our derivative contracts of approximately $7.88 per barrel of oil compared to the gain on settlements and monetization of our derivative contracts of approximately $12.06 per barrel of oil for the year ended June 30, 2015.

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Commodity prices are affected by many factors that are outside of our control, and we cannot accurately predict future commodity prices. Depressed commodity prices over an extended period of time could result in reduced cash from operating activities, potentially causing us to further reduce our capital expenditure program. Reductions in our capital expenditures could result in a reduction of production volumes.

Volume Variances

Sales volumes are another key driver of our earnings and net operating cash flow. Oil sales volumes decreased 4.8 MBbls per day in the year ended June 30, 2016 as compared to the prior fiscal year, resulting in lower revenues of $69.1 million. Natural gas sales volumes decreased by 9.9 Mcf per day in the year ended June 30, 2016, resulting in lower revenues of $7.1 million. Sales volumes decreased because of natural well declines, reduced drilling activity resulting in less new production, and irregular downtime due to interruptions on third party pipelines. In the current low commodity price environment, we expect to see further production declines due to natural declines and limited activity in the fields.

Costs and expenses and other (income) expense

	Year Ended June 30,												Increase (Decrease) Total $
	2016						2015
	Total $			Per BOE			Total $			Per BOE
	(In thousands, except per unit amounts)
Cost and expenses
Lease operating expense
Insurance expense	$	37,958		$	1.98		$	40,046		$	1.86		$	(2,088	)
Workover and maintenance		58,260			3.03			65,562			3.05			(7,302	)
Direct lease operating expense		249,855			13.01			357,927			16.64			(108,072	)
Total lease operating expense		346,073			18.02			463,535			21.55			(117,462	)
Production taxes		1,442			0.08			8,385			0.39			(6,943	)
Gathering and transportation		55,925			2.91			21,144			0.98			34,781
DD&A		339,516			17.67			705,521			32.81			(366,005	)
Accretion of asset retirement obligations		64,690			3.37			50,081			2.33			14,609
Impairment of oil and natural gas properties		2,813,570			146.47			2,421,884			112.63			391,686
Goodwill impairment		—			—			329,293			15.31			(329,293	)
General and administrative		102,736			5.35			116,500			5.42			(13,764	)
Total costs and expenses	$	3,723,952		$	193.87		$	4,116,343		$	191.42		$	(392,391	)
Other (income) expense
(Income) loss from equity method investees	$	10,746		$	0.56		$	17,165		$	0.80		$	(6,419	)
Other income-net		(3,596	)		(0.19	)		(4,176	)		(0.19	)		580
Gain on early extinguishment of debt		(1,525,596	)		(79.42	)		—			—			(1,525,596	)
Interest expense		405,658			21.12			323,308			15.03			82,350
Total other (income) expense	$	(1,112,788	)	$	(57.93	)	$	336,297		$	15.64		$	(1,449,085	)

Costs and expenses decreased $392.4 million in the year ended June 30, 2016 as compared to the year ended June 30, 2015, principally due to lower DD&A, goodwill impairment and lease operating expense, principally due to factors discussed further below. These decreases were partially offset by increases in the impairment of oil and natural gas properties, gathering and transportation, and accretion of asset retirement obligations.

At the end of each quarter, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to our full cost

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pool of oil and natural gas properties, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. As a result of our ceiling tests at the end of each quarter during fiscal 2016, we recognized ceiling test impairments of our oil and natural gas properties totaling $2,813.6 million during the year ended June 30, 2016. As a result of our ceiling tests at March 31, 2015 and June 30, 2015, we recognized ceiling test impairments of our oil and natural gas properties totaling $2,421.9 million during the year ended June 30, 2015.

During the year ended June 30, 2015, we recorded a non-cash impairment charge of $329.3 million to reduce the carrying value of goodwill to zero as of December 31, 2014. At December 31, 2014, we performed a goodwill impairment test after assessing relevant events and circumstances, primarily the decline in oil prices since September 30, 2014. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill at December 31, 2014.

Lease operating expense decreased $117.5 million in the year ended June 30, 2016 compared to the year ended June 30, 2015. This decrease was primarily due to lower direct lease operating expenses stemming from declining service costs resulting from the decline in commodity prices and decrease in demand for oil field services. Lease operating expense per BOE declined from $21.55 for the year ended June 30, 2015 to $18.02 for the year ended June 30, 2016.

Gathering and transportation expense increased $34.8 million in the year ended June 30, 2016 as compared to the prior fiscal year. This increase was primarily due to rent expense associated with the lease of the GIGS, which we entered into on June 30, 2015.

DD&A expense decreased $366.0 million in the year ended June 30, 2016 as compared to the year ended June 30, 2015, primarily due to a decrease in the DD&A per BOE rate of $15.14. The decrease in the DD&A rate in fiscal 2016 was primarily due to the reduction in our full cost pool due to the ceiling test impairments of our oil and natural gas properties in prior quarterly periods of fiscal year 2015 and 2016, partially offset by the reduction in proved reserve estimates.

General and administrative expense decreased $13.8 million in the year ended June 30, 2016 as compared to the prior fiscal year, primarily due to lower employee salary costs and lower stock-based compensation, partially offset by lower capitalized amounts and pre-petition restructuring costs of approximately $9.3 million.

Interest expense increased $82.4 million in fiscal 2016 as compared to the prior fiscal year, principally due to the acceleration of amortization of debt issuance costs and debt discount as well as interest on the Second Lien Notes, partially offset by interest reductions from repurchases of debt. On a per unit of production basis, interest expense increased from $15.03 per BOE in fiscal 2015 to $21.12 per BOE in fiscal 2016. However, in accordance with ASC 852, the Debtors have discontinued recording interest on debt classified as liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $52.8 million, or $2.75 per BOE, representing interest expense from the Petition Date through June 30, 2016.

During the year ended June 30, 2016, we acquired certain of our unsecured notes in aggregate principal amounts as follows: $506.0 million of 6.875% Senior Notes due 2024, $261.9 million of 7.5% Senior Notes due 2021, $148.9 million of 7.75% Senior Notes due 2019, $296.3 million of 8.25% Senior Notes due 2018 and $500.6 million of 9.25% Senior Notes due 2017. We acquired these notes in open market transactions at a total cost of approximately $215.9 million, plus accrued interest. In addition, in March 2016, certain bondholders holding $37 million in face value of our 3.0% Senior Convertible Notes requested for conversion. We recorded a gain on the purchases and conversion totaling approximately $1,525.6 million, net of associated debt issuance costs, debt discount and certain other expenses.

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Reorganization Items

Since the filing of the Bankruptcy Petitions, we have recorded $14.2 million in reorganization items, which represent the direct and incremental costs of being in bankruptcy, and primarily consist of professional fees incurred through June 30, 2016.

Income Tax Benefit

We recorded de minimis income tax benefit in the year ended June 30, 2016 compare to an income tax benefit of $613.4 million in the year ended June 30, 2015. The effective income tax expense/(benefit) rate for the year ended June 30, 2015 was (20.1%). The change in the effective tax rate is primarily due to the book loss for the period and our inability to currently record any additional net deferred tax assets due to a preponderance of negative evidence as to future realizability of these deferred tax assets. See Note 17 —  “Income Taxes” of Notes to our Consolidated Financial Statements in this Form 10-K.

Year Ended June 30, 2015 Compared to the Year Ended June 30, 2014

Our consolidated net loss attributable to common stockholders for the year ended June 30, 2015 was $2,445.3 million or $25.97 diluted net loss per share as compared to consolidated net income attributable to common stockholders of $6.6 million or $0.09 diluted income per share for the year ended June 30, 2014. This decrease was primarily due to higher costs and expenses including impairment of oil and natural gas properties, impairment of goodwill, lower oil and natural gas sales prices and higher interest expense partially offset by higher crude oil and natural gas sales volumes and gain on derivative financial instruments.

Revenue Variances

	Year Ended June 30,					Increase (Decrease)			Percent Increase (Decrease)
	2015		2014
			(In thousands)
Oil	$	1,052,731	$	1,104,208		$	(51,477	)		(4.7	)%
Natural gas		117,282		135,883			(18,601	)		(13.7	)%
Gain (loss) on derivative financial instruments		235,439		(86,968	)		322,407			370.7	%
Total Revenues	$	1,405,452	$	1,153,123		$	252,329			21.9	%

Revenues

Our consolidated revenues increased $252.3 million for the year ended June 30, 2015 as compared to the year ended June 30, 2014. Higher revenues were primarily due to higher oil sales volumes as a result of the EPL Acquisition and gain on derivative financial instruments, partially offset by lower commodity sales prices. Revenue variances related to commodity prices, sales volumes and hedging activities are presented in the following table and described below.

Price and Volume Variances

	Year Ended June 30,					Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
	2015		2014
												(In thousands)
Price Variance
Oil sales prices (per Bbl)(1)	$	68.99	$	100.59		$	(31.60	)		(31.4	)%	$	(346,353	)
Natural gas sales prices (per Mcf)(1)		3.13		4.15			(1.02	)		(24.6	)%		(33,336	)
Gain (loss) on derivative financial instruments (per BOE)		10.95		(5.29	)		16.24			307.0	%		322,407
Total price variance													(57,282	)
Volume Variance
Oil sales volumes (MBbls)		15,259		10,978			4,281			39.0	%		294,876
Natural gas sales volumes (MMcf)		37,472		32,754			4,718			14.4	%		14,735

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	Year Ended June 30,						Increase (Decrease)		Percent Increase (Decrease)			Revenue Increase (Decrease)
	2015			2014
												(In thousands)
BOE sales volumes (MBOE)	$	21,504		$	16,437		$	5,067		30.8	%
Percent of BOE from oil		71	%		67	%
Total volume variance												$	309,611
Total price and volume variance												$	252,329

(1) Commodity prices exclude the impact of derivative financial instruments.

Price Variances

Commodity prices are one of the key drivers of our earnings and net operating cash flow. Lower commodity prices decreased revenues by $379.7 million in the year ended June 30, 2015 as compared to the year ended June 30, 2014. Average oil prices decreased $31.60 per barrel in the year ended June 30, 2015, resulting in lower revenues of $346.4 million. Average natural gas prices decreased $1.02 per Mcf during the year ended June 30, 2015, resulting in lower revenues of $33.3 million. Our hedging activities partially offset the impact of the decrease in prices resulting in higher revenues of $322.4 million or $16.24 per BOE. The gain on derivatives for the year ended June 30, 2015 includes a gain on settlements and monetization of our derivative contracts of approximately $12.06 per barrel of oil compared to a loss on settlements of $1.58 per barrel of oil for the year ended June 30, 2014.

Volume Variances

Sales volumes are another key driver of our earnings and net operating cash flow. Oil sales volumes increased 11.7 MBbls per day in the year ended June 30, 2015 as compared to the prior fiscal year, resulting in higher revenues of $294.9 million. Natural gas sales volumes were also higher in the year ended June 30, 2015, increasing 12.9 MMcf per day for fiscal year 2015 as compared to the prior fiscal year, resulting in higher revenues of $14.7 million. The increase in sales volumes in the year ended June 30, 2015 was primarily due to production from assets acquired in the EPL Acquisition partially offset by the impact of natural decline.

Costs and expenses and other (income) expense

	Year Ended June 30,								Increase (Decrease) Total $
	2015				2014
	Total $		Per BOE		Total $		Per BOE
	(In thousands, except per unit amounts)
Cost and expenses
Lease operating expense
Insurance expense	$	40,046	$	1.86	$	31,183	$	1.90	$	8,863
Workover and maintenance		65,562		3.05		66,481		4.04		(919	)
Direct lease operating expense		357,927		16.64		268,083		16.31		89,844
Total lease operating expense		463,535		21.55		365,747		22.25		97,788
Production taxes		8,385		0.39		5,427		0.33		2,958
Gathering and transportation		21,144		0.98		23,532		1.43		(2,388	)
DD&A		705,521		32.81		414,026		25.19		291,495
Accretion of asset retirement obligations		50,081		2.33		30,183		1.84		19,898
Impairment of oil and natural gas properties		2,421,884		112.63		—		—		2,421,884
Goodwill impairment		329,293		15.31		—		—		329,293
General and administrative		116,500		5.42		96,402		5.87		20,098
Total costs and expenses	$	4,116,343	$	191.42	$	935,317	$	56.91	$	3,181,026

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	Year Ended June 30,												Increase (Decrease) Total $
	2015						2014
	Total $			Per BOE			Total $			Per BOE
	(In thousands, except per unit amounts)
Other (income) expense
(Income) loss from equity method investees	$	17,165		$	0.80		$	5,231		$	0.32		$	11,934
Other income-net		(4,176	)		(0.19	)		(3,298	)		(0.20	)		(878	)
Interest expense		323,308			15.03			162,728			9.90			160,580
Total other (income) expense	$	336,297		$	15.64		$	164,661		$	10.02		$	171,636

Costs and expenses increased $3,200 million in the year ended June 30, 2015 as compared to the year ended June 30, 2014, principally due to the impairment of oil and gas properties, the impairment of goodwill and higher DD&A expense. We also had higher lease operating expense, general and administrative expenses and accretion of asset retirement obligations, principally due to the EPL Acquisition and other factors discussed further below.

As a result of our ceiling test at March 31, 2015 and June 30, 2015, we recognized ceiling test impairments of our oil and natural gas properties totaling $2,421.9 million during the year ended June 30, 2015.

During the year ended June 30, 2015, we recorded a non-cash impairment charge of $329.3 million to reduce the carrying value of goodwill to zero as of December 31, 2014. At December 31, 2014, we performed a goodwill impairment test after assessing relevant events and circumstances, primarily the decline in oil prices since September 30, 2014. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill at December 31, 2014.

Lease operating expense increased $97.8 million in the year ended June 30, 2015 compared to the year ended June 30, 2014. This increase was primarily due to higher direct lease operating expenses stemming from the increase in producing properties resulting from acquisitions and from our capital program, partially offset by declining service costs in the last three quarters of fiscal year 2015 resulting from the decline in commodity prices and decrease in demand for oil field services. Lease operating expense per BOE declined from $22.25 for the year ended June 30, 2014 to $21.55 for the year ended June 30, 2015.

DD&A expense increased $291.5 million in the year ended June 30, 2015 as compared to the year ended June 30, 2014. DD&A expense increased $166.2 million as a result of higher net production. This was coupled with an increase in the DD&A per BOE rate of $7.62, which increased DD&A expense by $125.3 million. The increase in the DD&A rate in the year ended June 30, 2015 was due to the EPL Acquisition, the reclassification of exploratory wells in progress to evaluated properties and a reduction in proved reserve estimates.

Accretion of asset retirement obligations increased $19.9 million in the year ended June 30, 2015 as compared to the prior fiscal year. This increase was principally due to accretion of asset retirement obligations assumed in connection with the EPL Acquisition.

General and administrative expense increased $20.1 million in the year ended June 30, 2015 as compared to the prior fiscal year, primarily due to executive and employee severance costs totaling approximately $17.6 million and consulting fees associated with the integration of EPL.

Other (income) expense increased $171.6 million in the year ended June 30, 2015 as compared to the year ended June 30, 2014, principally due to higher interest expense due to increased borrowings. Interest expense increased $160.6 million in the year ended June 30, 2015 as compared to the year ended June 30, 2014, principally due to debt incurred and assumed in connection with the EPL Acquisition, the issuance of

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the Second Lien Notes and the write-off of a portion of the deferred debt issue costs associated with our Revolving Credit Facility. On a per unit of production basis, interest expense increased 51.8%, from $9.90 per BOE to $15.03 per BOE.

Income Tax Expense

We recorded income tax benefit of $613.4 million in the year ended June 30, 2015 compared to income tax expense of $35.0 million recorded in the year ended June 30, 2014. The effective income tax expense/(benefit) rate for the year ended June 30, 2015 was (20.1%) as compared to 65.9% for the year ended June 30, 2014. The decrease in the tax rate was primarily due: (i) the book loss for the year, (ii) the $329 million non-tax deductible goodwill impairment, and (iii) the $356.8 million increase in our valuation allowance. This increase in our valuation allowance was due to changes in our expectations regarding our future taxable income, consistent with net losses recorded during fiscal year 2015 (that were heavily influenced by oil and gas property impairments). In light of the form of the transaction related to the acquisition of EPL on June 3, 2014, the goodwill recognized as a result of the EPL Acquisition did not have tax basis; therefore, the goodwill impairment was nondeductible for tax purposes. See Note 17 — “Income Taxes” of Notes to our Consolidated Financial Statements in this Form 10-K.

Proved Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and natural 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 natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

	Year Ended June 30, 2016						Year Ended June 30, 2015
	Oil MMBbls		Natural Gas Bcf		MMBOE		Oil MMBbls		Natural Gas Bcf		MMBOE
Proved
Developed		66.3		121.1		86.6		94.0		188.0		125.3
Undeveloped		—		—		—		43.1		90.5		58.2
Total Proved		66.3		121.1		86.6		137.1		278.5		183.5

Our proved reserves decreased by 96.9 MMBOE or by approximately 53% from 183.5 MMBOE at June 30, 2015 to 86.6 MMBOE at June 30, 2016. The decrease was primarily due to:

• Downward revision of 54.3 MMBOE related to reclassification of proved undeveloped reserves to the contingent resource category. Due to the depressed commodity prices and our lack of capital resources to develop our properties, our proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result, we removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category on December 31, 2015 are still economic at current prices, but were reclassified to the contingent resource category because they were no longer expected to be drilled within five years of initial booking due to current constraints on our ability to fund development drilling. Due to continued constraints on available capital, our proved reserve estimates do not include any proved undeveloped reserves as of June 30, 2016. Further, the reclassification of proved undeveloped reserves also had an impact on the proved developed reserves volumes as it shortened the economic life of fields and thereby reduced economic production from the proved developed reserves category.

• Production of 19.1 MMBOE during the year

• Downward revision of 28.7 MMBOE resulting from reduced oil and gas prices and shortened economic field life, and

• Downward revision of 8.1 MMBOE resulting from technical revisions

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These were offset by:

• Reserve additions of 1.7 MMBOE, and

• Addition of 11.6 MMBOE due to acquisition of the remaining equity interests of M21K

Liquidity and Capital Resources

Overview

As of June 30, 2016, we had cash and cash equivalents of approximately $203.3 million and no available borrowing capacity under our Revolving Credit Facility. As of June 30, 2016, the total carrying value of our indebtedness was $2,863.8 million of which $2,764.0 million is classified as liabilities subject to compromise and $99.8 million is classified as current on our consolidated balance sheets. Our current indebtedness of $99.8 million of secured indebtedness outstanding consists of $99.4 million under our Revolving Credit Facility and $0.4 million of payment “in-kind” (“PIK”) interest under restructuring term sheet with the Lenders under First Lien Credit Agreement. Our indebtedness classified as liabilities subject to compromise includes our debt owed to third parties comprised of $1,450 million of Second Lien Notes, $4.7 million in other secured indebtedness and $1,309.3 million of unsecured notes. These amounts do not include the $325 million intercompany note owed to EGC by EPL, the $266.6 million of EPL’s 8.25% Senior Notes repurchased by EGC in open market transactions and which continue to be held by EGC, the $471.1 million of EGC’s 9.25% Senior Notes due 2017 purchased by EGC in open market transactions and which continue to be held by EGC, or potentially certain of the Debtors’ other intercompany payable balances, which may also be eliminated by the Plan.

Liquidity Before Filing Under Chapter 11 of the United States Bankruptcy Code

We have historically funded our operations primarily through cash flows from operating activities, borrowings under our Revolving Credit Facility, proceeds from the issuance of debt and equity securities and proceeds from asset sales. However, future cash flows are subject to a number of variables, and are highly dependent on the prices we receive for oil and natural gas. Oil and natural gas prices declined severely during fiscal year 2015 and have declined even further with lower prices throughout fiscal 2016. The price of WTI crude oil per barrel dropped below $27.00 per barrel in January 2016 for the first time in twelve years. Although oil prices have rebounded above $40.00 per barrel through September 2016, there is still significant volatility in commodity prices and these prices are still significantly lower than the industry has experienced in recent years. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position.

As a result of continued decreases in commodity prices and our substantial debt burden, we continued throughout the third quarter of fiscal 2016 to work with our financial and legal advisors to analyze a variety of solutions to reduce our overall financial leverage, while maintaining primary focus on preserving liquidity. As part of this process, we engaged in discussions with certain of our debtholders and other stakeholders to develop and implement a comprehensive plan to restructure our balance sheet. As part of these ongoing discussions, on February 16, 2016, we had elected to enter into the 30-day grace period under the terms of the indenture governing EPL’s 8.25% Senior Notes due February 2018 to extend the timeline for making the cash interest payment to March 17, 2016.

On March 15, 2016, as part of our ongoing discussions with certain of our debtholders, we elected to make the deferred interest payment on the 8.25% Senior Notes, while electing not to make the interest payments due on the Second Lien Notes and on EGC’s 6.875% Senior Notes due 2024, commencing a new 30-day grace period. During the new 30-day grace period, we continued discussions with certain Second Lien Noteholders and a steering committee of the Lenders under our Revolving Credit Facility regarding a potential restructuring. On April 11, 2016, we entered into the Restructuring Support Agreement with certain of the Second Lien Noteholders. Pursuant to the Plan, we expect to eliminate more than $2,800 million aggregate principal amount of debt and accrued interest held by/due to third-parties, substantial intercompany debt (including the $325 million intercompany note owed to EGC by EPL, the $266.6 million of the 8.25% Senior Notes purchased by EGC in open market transactions and potentially certain of the Debtors’ other intercompany payable balances) as well as the $471.1 million of EGC’s 9.25% Senior Notes repurchased by

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EGC in open market transactions. As the Plan eliminates substantially all of our prepetition indebtedness other than indebtedness under our Revolving Credit Facility, it will result in a significantly deleveraged capital structure.

Liquidity After Filing Under Chapter 11 of the United States Bankruptcy Code

Subject to certain exceptions under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the filing of the Bankruptcy Petitions. Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’ property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

The Bankruptcy Court has approved payment of certain pre-petition obligations, including payments for employee wages, salaries and certain other benefits, customer programs, taxes, utilities, insurance, surety bond premiums as well as payments to critical vendors and possessory lien vendors. Despite the liquidity provided by our existing cash on hand, our ability to maintain normal credit terms with our suppliers may become impaired. We may be required to pay cash in advance to certain vendors and may experience restrictions on the availability of trade credit, which would further reduce our liquidity. If liquidity problems persist, our suppliers could refuse to provide key products and services in the future. In addition, due to the public perception of our financial condition and results of operations, in particular with regard to our potential failure to meet our debt obligations, some vendors could be reluctant to enter into long-term agreements with us.

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 proceedings (approximately $24.0 million through June 30, 2016, of which approximately $14.2 million is classified as reorganization items on our consolidated statements of operations and $0.5 million was capitalized as debt issue costs, with the remainder included in general and administrative expenses) and we expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. The Company believes it has sufficient liquidity, including approximately $203 million of cash on hand as of June 30, 2016 and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 proceedings for minimum operating and capital expenditures and for working capital purposes and excluding principal and interest payments on our outstanding debt. As such, we expect to pay vendor, royalty and surety obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders approving such payments. We do not intend to seek debtor-in-possession financing at this time.

Upon our emergence from the Chapter 11 Cases, we are required to have liquidity of at least $90 million per the restructuring term sheet with the Lenders under our First Lien Credit Agreement. We believe that our capital resources from existing cash balances, borrowings under any new capacity created under our Exit Facility, and anticipated cash flow from operating activities will be adequate to execute our corporate strategies.

Given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our operations, our liquidity needs could be significantly higher than we currently anticipate. Our ability to maintain adequate liquidity through the reorganization process and beyond depends on our ability to successfully implement the Plan (or another Chapter 11 plan), successful operation of our business, and appropriate management of operating expenses and capital spending. Our anticipated liquidity needs are highly sensitive to changes in each of these and other factors. If we are unable to meet our liquidity needs, we may have to take other actions to seek additional financing to the extent available or we could be forced to consider other alternatives to maximize potential recovery for the creditors, including possible sale of the Company or certain material assets pursuant to Section 363 of the Bankruptcy Code, or a liquidation under Chapter 7 of the Bankruptcy Code.

Under the final order approving the Debtors’ use of cash collateral, the Debtors’ have the conditional authority, subject to the terms and conditions of the Bankruptcy Court’s orders, the Restructuring Support

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Agreement, and the cash collateral budget, to use cash collateral for a certain period from the Petition Date and the Debtors have agreed to pursue the confirmation and implementation of the Plan within that certain period. The Debtors’ use of cash collateral is critical to their ability to operate during the course of the Chapter 11 Cases, to remain current on their post-petition operating costs, to pursue reorganization pursuant to the Plan and to emerge successfully as a going concern from the Chapter 11 Cases.

Our liquidity may be further adversely affected if the BOEM requires us to provide additional bonding as a means to assure our decommissioning obligations, such as the plugging of wells, the removal of platforms and other offshore facilities, the abandonment of offshore pipelines and the clearing of the seafloor of obstructions, or if the surety companies providing such bonds on our behalf require us to provide additional cash collateral for such new or existing bonds. Any further expense in providing additional bonds or restrictions on our cash to collateralize existing bonds or new bonds would further reduce our liquidity.

Our Indebtedness and Available Credit

As of June 30, 2016, we had total aggregate indebtedness of $2,863.8 million held by third parties as described in greater detail below, comprised of $99.8 million of secured indebtedness outstanding, consisting of $99.4 million under our Revolving Credit Facility and $0.4 million of payment “in-kind” (“PIK”) interest under the Exit Facility Term Sheet, $1,450 million of senior secured second lien notes, $4.7 million in other secured indebtedness and $1,309.3 million of unsecured notes. The maturity dates for our outstanding notes (excluding $266.6 million of the 8.25% Senior Notes, which were purchased by EGC in open market transactions at a total cost of approximately $11.4 million, including accrued interest of $10.4 million, and continue to held by EGC), which are all classified as liabilities subject to compromise, are as follows:

• 9.25% Senior Notes due December 15, 2017 ($249.4 million)

• 8.25% Senior Notes due February 15, 2018 ($213.7 million)

• 3.0% Convertible Notes due December 15, 2018 ($363.0 million)

• 7.75% Senior Notes due June 15, 2019 ($101.1 million)

• 11.0% Senior Secured Second Lien Notes due March 15, 2020 ($1,450 million)

• 7.50% Senior Notes due December 15, 2021 ($238.1 million)

• 6.875% Senior Notes due March 15, 2024 ($144.0 million)

On the date that Debtors will consummate the transactions contemplated by the Plan (the date of such consummation, the “Effective Date”), the existing notes above are expected to be converted into New Equity of the New Entity. As a result, the obligations of the Debtors with respect to these outstanding notes above will be cancelled and discharged as of the Effective Date. Any outstanding indebtedness of the New Entity will only be pursuant to our Exit Facility which we expect to have in place upon emergence from Chapter 11.

Revolving Credit Facility.  The First Lien Credit Agreement or Revolving Credit Facility currently has a maximum facility amount and borrowing base of $327.2 million, of which such amount $99.4 million is the borrowing base under the sub-facility established for EPL. As of June 30, 2016, we had $99.4 million in borrowings and $227.8 million in letters of credit issued under our First Lien Credit Agreement. The maturity date of the First Lien Credit Agreement is April 9, 2018. Our Revolving 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.

On February 29, 2016, the Thirteenth Amendment became effective and on March 14, 2016, the Fourteenth Amendment became effective, extending the term of the Thirteenth Amendment until April 15, 2016.

The Thirteenth and Fourteenth Amendments provided that we were not required to deliver a compliance certificate for the fiscal quarter ended December 31, 2015 until their respective expiration dates. The following additional changes to the First Lien Credit Agreement became effective upon the execution of the Thirteenth Amendment:

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• Prohibiting EGC and EPL from borrowing under the First Lien Credit Agreement before March 15, 2016.

• Requiring EGC and EPL to deposit all cash and investments in accounts covered by control agreements in favor of the administrative agent.

• Allowing for EGC and EPL to get replacement letters of credit under the First Lien Credit Agreement without satisfying the credit extension conditions in the First Lien Credit Agreement so long as the replacement letter of credit does not have an aggregate face amount in excess of the available amount of the letter of credit being replaced and certain other conditions set forth in the Thirteenth Amendment are met.

The Fourteenth Amendment provided for the reduction of our borrowing base under the First Lien Credit Agreement. The borrowing base under the First Lien Credit Agreement as of the effectiveness of the Fourteenth Amendment was reduced from $500 million to $377.8 million, with such reduction effectively removing any further borrowing capacity under the First Lien Credit Agreement beyond an aggregate amount equal to the amount of outstanding letters of credit that have been issued thereunder plus the amount of outstanding loans to EPL thereunder. In connection with such reduction under the Fourteenth Amendment, we unwound certain hedging transactions and used the proceeds therefrom to repay amounts of outstanding loans to EPL under the First Lien Credit Agreement, with such repayments resulting in an automatic and permanent reduction in our borrowing base. This further reduction in borrowing base was for both the overall borrowing base under the First Lien Credit Agreement as well as the borrowing base specific to EPL, and in each case, the reduction was in an amount equal to the full extent of the aggregate amount of repaid principal relating to such unwound hedging transactions.

The Fourteenth Amendment continued to allow us to get replacement letters of credit under the First Lien Credit Agreement without satisfying credit extension conditions so long as the replacement letter of credit did not have an aggregate face amount in excess of the available amount of the letter of credit being replaced and certain other conditions set forth in the Fourteenth Amendment were met.

On the Petition Date, however, the Debtors filed the Bankruptcy Petitions, which constituted an event of default under the Revolving Credit Facility and accelerated the indebtedness thereunder. Pursuant to the Restructuring Support Agreement entered into on April 11, 2016, the Debtors, on behalf of the holders of the First Lien Claims arising on account of the Revolving Credit Facility and subject to further negotiations with the Lenders, have agreed to use their best efforts to ensure that at emergence from the Chapter 11 proceedings, the amount drawn under the Revolving Credit Facility either (i) remains outstanding or (ii) is refinanced with a new facility with terms acceptable to the Majority Restructuring Support Parties; provided, however that (a) $227.8 million of letters of credit usage remains outstanding and (b) other terms, including a borrowing base redetermination holiday, are acceptable to the Debtors and the Majority Restructuring Support Parties. If the Debtors are unable to obtain the foregoing treatment of the First Lien Claims, then the Debtors will use their best efforts to obtain treatment acceptable to the Debtors and the Majority Restructuring Support Parties.

In addition to the indebtedness outstanding under the First Lien Credit Agreement, we have substantial additional indebtedness outstanding as described below. The filing of the Bankruptcy Petitions constituted an event of default with respect to these existing debt obligations, accordingly our pre-petition secured indebtedness under the Revolving Credit Facility, Second Lien Notes and EPL and EGC unsecured notes became immediately due and payable and any efforts to enforce such payment obligations are automatically stayed as a result of the Chapter 11 Cases. In addition, as a result of the covenant violations that existed at March 31, 2016 that were not cured prior to the filing of the Bankruptcy Petitions, all of our outstanding indebtedness were classified as current at March 31, 2016, and we accelerated the amortization of the associated debt premium and original issue discount, fully amortizing those amounts as of March 31, 2016. In addition, except for amounts related to the Revolving Credit Facility, we accelerated the amortization of the remaining debt issuance costs related to our outstanding indebtedness, fully amortizing those costs as of March 31, 2016. Any efforts to enforce such payment obligations are automatically stayed as a result of the Chapter 11 Cases. We currently believe that it is probable that we may enter into a potential restructuring agreement with the Lenders under our Revolving Credit Facility. Accordingly, we have not accelerated the

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amortization of remaining debt issue costs related to the Revolving Credit Facility. We continue to accrue interest on the Revolving Credit Facility subsequent to the Petition Date since we anticipate that such interest will be allowed by the Bankruptcy Court to be paid to the Lenders. However, for all our other indebtedness, in accordance with accounting guidance in ASC 852, Reorganizations, we have accrued interest only up to the Petition Date. Additional information regarding the Chapter 11 proceedings is included in Note 3 —  Chapter 11 Proceedings, Liquidity and Capital Resources and Note 8 — Long Term Debt to Consolidated Financial Statements in this Form 10-K.

Second Lien Notes.  On March 12, 2015, EGC issued $1,450 million in aggregate principal amount of the Second Lien Notes, which are senior secured second lien notes due March 15, 2020. The offering of the Second Lien Notes resulted in net proceeds of approximately $1,355 million after deducting the original issue discount and direct offering costs. The Second Lien Notes were sold to investors at a discount of 96.313% of principal, for a yield to maturity at issuance of 12.0%. The Second Lien Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act. As such, the Second Lien Notes and the related guarantees have not been, and will not be, registered under the Securities Act or the securities laws of any other jurisdiction. EGC incurred underwriting and direct offering costs of $41.7 million which were recorded as debt issuance costs.

The Second Lien Notes were issued pursuant to an indenture, dated March 12, 2015 (the “2015 Indenture”), among EGC, the guarantors and U.S. Bank National Association, as trustee. The Second Lien Notes are secured by second-priority liens on substantially all of EGC and its subsidiary guarantors’ assets and all of EXXI USA’s equity interests in EGC, in each case to the extent such assets secure our Revolving Credit Facility. The liens securing the Second Lien Notes and the related guarantees are contractually subordinated to the liens on such assets securing our Revolving Credit Facility and any other priority lien debt, to the extent of the value of the collateral securing such obligations, pursuant to the terms of an intercreditor agreement, and to certain other secured indebtedness, to the extent of the value of the assets subject to the liens securing such indebtedness.

8.25% Senior Notes.  On June 3, 2014, EGC assumed the 8.25% Senior Notes in the 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, governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL’s obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

6.875% Senior Notes.  On May 27, 2014, EGC issued the 6.875% Senior Notes which consisted of $650 million in aggregate principal amount due March 15, 2024. On June 1, 2015, we completed a registered offer to exchange the 6.875% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. The indenture governing the 6.875% Senior Notes, among other things, limits 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 natural gas business.

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3.0% Senior Convertible Notes.  On November 18, 2013, Energy XXI Ltd, sold $400 million face value 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 election of Energy XXI Ltd, 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 accordingly the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.

As described in the indenture governing the 3.0% Senior Convertible Notes, the 3.0% Senior Convertible Notes can be converted in multiples of $1,000 principal amount, upon request by the bondholder, if prior to September 15, 2018, during the five consecutive business-day period following any ten consecutive trading-day period in which the trading price per $1,000 principal amount of 3.0% Senior Convertible Notes for each trading day during such ten trading-day period was less than 98% of the closing sale price of our common stock for each trading day during such ten trading-day period multiplied by the then current conversion rate. In March 2016, each $1,000 principal amount of 3.0% Senior Convertible Notes were trading substantially lower than 98% of the value of our common stock multiplied by the then current conversion rate. Accordingly, certain bondholders holding $37 million in face value of our 3.0% Senior Convertible Notes requested conversion into shares of our common stock. Upon conversion, we elected to issue shares of our common stock and delivered 915,385 shares of our common stock with fractional shares settled in cash. We followed the guidance in ASC 470-20, Debt with Conversion and Other Options, to record such conversion which allows for the allocation of fair value of the consideration transferred to the bondholder between the liability and equity components of the original instrument, recognition of gain or loss on debt extinguishment and allocation of remaining consideration transferred to reacquire the equity component. Accordingly, we recorded a debt extinguishment gain of approximately $33.2 million and proportionately adjusted the related debt issue costs, accrued interest and original debt issue discount.

7.5% Senior Notes.  On September 26, 2013, EGC issued at par $500 million in aggregate principal amount of 7.5% unsecured senior notes due December 15, 2021 (the “7.5% Senior Notes”). In April 2014, we completed a registered 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. The indenture governing the 7.5% Senior Notes limits, among other things, 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, consolidate or sell all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

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

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

4.14% Promissory Note.  In September 2012, we entered into a promissory note of $5.5 million to acquire certain other property and equipment. Under this note, we are required to make monthly payments 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.

For more information regarding our outstanding indebtedness, see Note 8 — “Long Term Debt” of Notes to our Consolidated Financial Statements in this Form 10-K.

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BOEM Bonding Requirements

The future cost of compliance with our existing supplemental bonding requirements, including such bonding obligations as reflected in the Long-Term Plan approved and executed by the BOEM on February 25, 2016, or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding rules applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide cash collateral to support the issuance of such bonds or other surety. While we are currently in compliance, we can provide no future assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient operating cash flows to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds as requested, the BOEM may have any of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties, and any one or more of such actions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. On June 28, 2016, we submitted an amended and supplemental plan to the BOEM as required and are currently awaiting their further response. For more information about the BOEM’s supplement bonding requirements, see “— Known Trends and Uncertainties — BOEM Supplemental Financial Assurance and/or Bonding Requirements.”

Potential Divestitures

We may decide to divest of certain non-core assets subject to approval of the Bankruptcy Court. There can be no assurance any such potential transactions will prove successful. We cannot provide any assurance that we will be able to sell these assets on satisfactory terms, if at all.

Capital Expenditures

For fiscal year 2016, we incurred capital costs of approximately $165 million, of which approximately $57 million was spent on development of our core properties and $108 million on other assets. Our initial fiscal year 2017 capital budget, excluding any potential acquisitions, is expected to be approximately $163 million. Approximately 63% of our 2017 capital budget is expected to be focused on development of our core properties and the remainder on other assets. We have historically funded our capital expenditure program and contractual commitments, from cash on hand, cash flows from operations, and borrowings under our Revolving Credit Facility. Since the filing of the Bankruptcy Petitions, our principal sources of liquidity have been limited to cash flow from operations and cash on hand. The Company believes it has sufficient liquidity, including its cash on hand as of June 30, 2016 and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 proceedings for minimum operating and capital expenditures and for working capital purposes excluding principal and interest payments on our outstanding debt. However, given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our operations, our liquidity needs could be significantly higher than we currently anticipate. Our long-term liquidity requirements, the adequacy of our capital resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a Chapter 11 plan has been confirmed, if at all, by the Bankruptcy Court. In addition to the cash requirements necessary to fund ongoing operations, we have incurred and expect that we will continue to incur significant professional fees and other costs in connection with the administration of the Chapter 11 proceedings.

If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and be unable to continue as a going concern and will likely be required to significantly reduce, delay or eliminate capital expenditures, implement further cost reductions, seek other financing alternatives or seek the sale of some or all of our assets. If we limit, defer or eliminate our capital expenditure plan or are unsuccessful in developing reserves and adding production through our capital program or our cost-cutting efforts are too overreaching, the value of our oil and natural gas properties and our financial condition and results of operations could be adversely affected.

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Cash Flows

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

	Year Ended June 30,
	2016			2015			2014
	(In thousands)
Net cash provided by (used in) operating activities	$	(166,655	)	$	330,753		$	545,460
Net cash used in investing activities		(122,913	)		(460,448	)		(1,544,575	)
Net cash provided by (used in) financing activities		(264,022	)		740,737			1,144,921
Net increase (decrease) in cash and cash equivalents	$	(553,590	)	$	611,042		$	145,806

Operating Activities.  Net cash used in operating activities for the fiscal year 2016 was $166.7 million as compared to net cash provided by operating activities of $330.8 million for the fiscal year 2015. The use of cash for operating activities for the year ended June 30, 2016 compared to cash provided by operating activities for the year ended June 30, 2015 was due primarily to lower oil and natural gas prices, lower proceeds from monetizations and cash settlements of derivative financial instruments and higher interest expense.

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 continuing decline in production volumes, one of the key drivers of generating net operating cash flows.

Investing Activities.  For the fiscal years 2016 and 2015, our cash used for capital expenditures and acquisitions totaled $114.7 million and $724.1 million, respectively. The decrease in net cash used in investing activities in fiscal year 2016 compared to fiscal year 2015 was primarily due to the reduction in capital expenditures, partially offset by a reduction in the proceeds from the sale of properties.

Financing Activities.  Cash used in financing activities was $264.0 million for the year ended June 30, 2016 as compared to cash provided by financing activities of $740.7 million for fiscal year 2015. During the year ended June 30, 2016, cash used in financing activities consists primarily of $227.9 million used in settlement of the repurchase of a portion of our senior notes and payments on derivative instruments premium financing, $25.2 million used in repayment of debt assumed in the M21K Acquisition and dividends to preferred shareholders of $5.7 million. During the year ended June 30, 2015, financing activities include net proceeds of $1,355 million from the issuance of the Second Lien Notes (after payment of $41.7 million of debt issuance costs) and net repayments on our Revolving Credit Facility of $539.0 million.

Contractual Obligations and Other Commitments

The table below summarizes our contractual obligations and other commitments as of June 30, 2016. Under the Bankruptcy Code, the Debtors have the right to assume or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a Debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing.

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The table does not reflect any potential changes to our contractual obligations and other commitments that may result from the Chapter 11 reorganization process and activities contemplated by the Plan. For example, the Plan contemplates that approximately $2,764.0 million of our debt obligations reflected in the table below would be converted into New Equity. Other contractual obligations and commitments may be amended or terminated. The table below does not include contractual interest payment obligations that would have been required for the original term of debt instruments that are classified as liabilities subject to compromise on our consolidated balance sheets.

	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)	$	2,863,844	$	2,863,844	$	—	$	—	$	—
Interest on long-term debt(1)		31,842		17,252		14,590		—		—
Operating leases(2)		440,956		37,933		75,955		94,871		232,197
Total contractual obligations		3,336,642		2,919,029		90,545		94,871		232,197
Other Obligations
Asset retirement obligations(3)		537,619		71,717		107,233		135,903		222,766
Performance bond premiums(4)		6,093		6,093		—		—		—
Total obligations	$	3,880,354	$	2,996,839	$	197,778	$	230,774	$	454,963

(1) See Note 8 — “Long-Term Debt” of Notes to our Consolidated Financial Statements in this Form 10-K for details of our long-term debt.

(2) See Note 16 — “Commitments and Contingencies” of Notes to our Consolidated Financial Statements in this Form 10-K for discussion of these commitments.

(3) See Note 9 — “Asset Retirement Obligations” of Notes to our Consolidated Financial Statements in this Form 10-K for details of asset retirement obligations. The obligations reflected above are discounted. In addition, the table above does not include performance bonds totaling $388.0 million and letters of credit of $225 million which support our asset retirement obligations.

(4) See Note 16 — “Commitments and Contingencies” of Notes to our Consolidated Financial Statements in this Form 10-K. As of June 30, 2016, our total annual premium expense for supplemental bonding totaled $6.1 million. The BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties.

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, 2016, the material off-balance sheet transactions entered into by us include operating lease agreements. 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 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.

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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 natural gas reserves, which are highly sensitive to changes in oil and natural gas prices that have been volatile in recent years. To the extent reserves are adversely impacted by reductions in oil and natural gas prices, we could experience increased depreciation, depletion and amortization expense and full cost ceiling impairments in future periods.

Presentation.  For periods subsequent to filing the Bankruptcy Petitions, we have prepared our consolidated financial statements in accordance with ASC 852, Reorganizations. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Pre-petition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

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. Other items subject to estimates and assumptions include fair value estimates used in accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; valuation of derivative financial instruments; reorganization items and liabilities subject to compromise, among others. 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 differences may be material.

Proved Oil and Natural Gas Reserves.  Proved oil and natural gas reserves are currently defined by the SEC as those volumes of oil and natural 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 natural 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 Natural Gas Properties.  We use the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural 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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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 associated with unevaluated properties are transferred to evaluated properties upon the earlier of (i) a determination as to whether there are any proved reserves related to the properties, (ii) a determination that the capital costs associated with the development of these properties will not be available, or (iii) ratably over a period of time of not more than four years.

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. Estimated future production volumes from oil and natural 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 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.

Due to the depressed commodity price environment and our lack of capital resources to develop our properties, our proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result we removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category on December 31, 2015 are still economic at current prices, but were reclassified to the contingent resource category because they were no longer expected to be drilled within five years of initial booking due to current constraints on our ability to fund development drilling. Due to continued constraints on available capital, our proved reserve estimates do not include any proved undeveloped reserves as of June 30, 2016.

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 reserve 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 the year ended June 30, 2014 with the EPL Acquisition and was recorded to our oil and gas reporting unit.

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At December 31, 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 necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014.

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 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.  Historically, we have utilized 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. Derivative instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations.

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 IRC 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. In light of changes in our expectations regarding our future taxable income, consistent with the results of operations for the fiscal year 2015 (heavily affected by impairments), we recorded an increase in our valuation allowance of $356.8 million resulting in a balance of $365.0 million at June 30, 2015. We recorded this increase to our valuation allowance against our net deferred tax assets due to our judgment that our existing U.S. federal and State of Louisiana net operating loss 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.

85

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

For a discussion of recent accounting pronouncements and the expected impact that the guidance could have on our Consolidated Financial Statements, see Note 2 — “Summary of Significant Accounting Policies and Recent Accounting Pronouncements” of Notes to our Consolidated Financial Statements in this Form 10-K.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

General

We are exposed to a variety of market risks including commodity price risk and interest rate risk. We address these risks through a program of risk management which has historically included the use of derivative instruments. At June 30, 2016, we had no outstanding derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we were a party at June 30, 2016, and from which we may incur future gains or losses from changes in market interest rates or commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

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 are volatile and may fluctuate widely. Oil and natural gas price declines such as the recent declines adversely affect our revenues, cash flows and profitability. The Company continues to incur significant losses from operations. As a result of the depressed pricing environment, further declines could impact the extent to which we develop portions of our oil and natural gas properties, and could possibly include temporarily shutting in certain wells that are uneconomic to produce. Due to the depressed commodity prices and our lack of capital resources to develop our properties, all of our proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result, we removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category on December 31, 2015 are still economic at current prices, but were reclassified to the contingent resource category because they are no longer expected to be drilled within five years of initial booking due to current constraints on our ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $336.5 million as being uneconomical and transferred such amounts to the full cost pool, subject to amortization. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operating activities and the value of our assets.

Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The energy markets have historically been very volatile, and there can be no assurance that crude oil and natural gas prices will improve.

We have historically utilized commodity-based derivative instruments with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas, including financially settled crude oil and natural gas zero-cost collars and three-way collars. Any gains or losses resulting from the change in fair value from hedging transactions and from the settlement of hedging contracts are recorded in earnings as a component of revenues.

86

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.

The Fourteenth Amendment further provided that we unwind certain hedging transactions and use the proceeds therefrom to repay amounts of outstanding loans to EPL under the First Lien Credit Agreement, and for such repayments to then result in an automatic and permanent reduction in our borrowing base. Accordingly, on March 15, 2016, we unwound and monetized all of our outstanding crude oil and natural gas contracts and received $50.6 million, which was used for such repayment. At June 30, 2016, we had no outstanding derivative contracts. For a complete discussion of our commodity derivatives, please see Note 10 — Derivative Financial Instruments of Notes to 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 Revolving Credit Facility, and the terms of such facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base. Historically, we have managed 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. Due to the filing of the Bankruptcy Petitions, we are no longer paying interest on our fixed rate indebtedness (other than certain capital lease obligations). Therefore, we are exposed to interest rate risk on almost all of the indebtedness on which we are paying interest, specifically our Revolving Credit Facility. As of June 30, 2016, we had $99.8 million of floating-rate debt. A 10% change in floating interest rates on period-end floating rate debt balances would change annual interest expense by approximately $9,980. 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 and future 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 our interest rate exposure on invested funds is not material.

87

Item 8. Financial Statements and Supplementary Data

	Page
Management’s Report on Internal Control over Financial Reporting		89
Report of Independent Registered Public Accounting Firm		90
Report of Independent Registered Public Accounting Firm		91
Report of Independent Registered Public Accounting Firm		92
Consolidated Financial Statements
Consolidated Balance Sheets as of June 30, 2016 and 2015		93
Consolidated Statements of Operations for the Years Ended June 30, 2016, 2015 and 2014		95
Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended June 30, 2016, 2015 and 2014		96
Consolidated Statements of Cash Flows for the Years Ended June 30, 2016, 2015 and 2014		97
Notes to Consolidated Financial Statements		98

88

MANAGEMENT’S ANNUAL 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, 2016. 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 (2013).

Based on this assessment, our management has concluded that, as of June 30, 2016, our internal control over financial reporting was effective based on those criteria.

BDO USA, 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, 2016. This report, dated September 27, 2016, appears on the following page.

89

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Energy XXI Ltd
Houston, Texas

We have audited the accompanying consolidated balance sheets of Energy XXI Ltd and subsidiaries (Debtor-in-Possession) as of June 30, 2016 and 2015 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the years then ended. In connection with our audits of the consolidated financial statements, we have also audited the financial statement schedule listed in Item 15(a)(2) as of and for the years ended June 30, 2016 and 2015. These consolidated financial statements and schedule are the responsibility of the Company’s management. 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, 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 financial position of Energy XXI Ltd and subsidiaries (Debtor-in-Possession) at June 30, 2016 and 2015, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Also in our opinion, the related financial statement schedule as of and for the years ended June 30, 2016 and 2015, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Notes 1 and 3 to the consolidated financial statements, the Company is currently operating pursuant to Chapter 11 of the U.S. Bankruptcy Code, having filed voluntary petitions in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. There are no assurances as to management’s ability to obtain confirmation of a plan of reorganization under the Bankruptcy Code, which raises substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Energy XXI Ltd and subsidiaries’ (Debtor-in-Possession) internal control over financial reporting as of June 30, 2016, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 27, 2016 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP
 
Houston, Texas
September 27, 2016

90

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Energy XXI Ltd
Houston, Texas

We have audited Energy XXI Ltd and subsidiaries’ (Debtor-in-Possession) internal control over financial reporting as of June 30, 2016, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Energy XXI Ltd and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, incorporated by reference in the accompanying “Item 9A, Management’s Annual Report on Internal Control over Financial Reporting.” Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 Ltd and subsidiaries (Debtor-in-Possession) maintained, in all material respects, effective internal control over financial reporting as of June 30, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Energy XXI Ltd and subsidiaries (Debtor-in-Possession) as of June 30, 2016 and 2015, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the years then ended and our report dated September 27, 2016 expressed an unqualified opinion thereon.

Our report contains an explanatory paragraph that states that the Company is currently operating pursuant to Chapter 11 of the U.S. Bankruptcy Code, having filed voluntary petitions in the United States Bankruptcy Court for the Southern District of Texas, Houston Division and there are no assurances as to management’s ability to obtain confirmation of a plan of reorganization under the Bankruptcy Code, which raises substantial doubt about the Company’s ability to continue as a going concern.

/s/ BDO USA, LLP
 
Houston, Texas
September 27, 2016

91

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and
Stockholders of Energy XXI Ltd

We have audited the accompanying consolidated statements of operations, stockholders’ equity, and cash flows of Energy XXI Ltd (formerly Energy XXI (Bermuda) Limited, a Bermuda Corporation) and subsidiaries (the “Company”) for the year ended June 30, 2014. Our audit also included the financial statement schedule included in Item 15(a)(2) as of June 30, 2014, and for the year then ended. 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 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 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 audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Energy XXI Ltd and subsidiaries for the year 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 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ UHY LLP

Houston, Texas

August 25, 2014, except for the effects of the restatement
disclosed in Note 22 to the consolidated financial
statements in Form 10-K for the year ended June 30, 2015,
as to which the date is September 29, 2015

92

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share information)

	June 30, 2016		June 30, 2015
ASSETS
Current Assets
Cash and cash equivalents	$	203,258	$	756,848
Accounts receivable, net
Oil and natural gas sales		63,644		100,243
Joint interest billings		8,770		12,433
Other		5,219		43,513
Prepaid expenses and other current assets		29,028		24,298
Restricted cash		38,965		9,359
Derivative financial instruments		—		22,229
Total Current Assets		348,884		968,923
Property and Equipment
Oil and natural gas properties, net – full cost method of accounting, including $42.2 million and $436.4 million of unevaluated properties not being amortized at June 30, 2016 and 2015, respectively		603,155		3,570,759
Other property and equipment, net		17,610		21,820
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		620,765		3,592,579
Other Assets
Derivative financial instruments		—		3,898
Equity investments		—		10,835
Restricted cash		25,548		32,667
Other assets and debt issuance costs, net of accumulated amortization		30,237		81,927
Total Other Assets		55,785		129,327
Total Assets	$	1,025,434	$	4,690,829
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current Liabilities
Accounts payable	$	44,184	$	156,339
Accrued liabilities		40,428		155,306
Asset retirement obligations		71,717		33,286
Derivative financial instruments		—		2,661
Current maturities of long-term debt		99,836		11,395
Total Current Liabilities		256,165		358,987
Long-term debt, less current maturities		—		4,597,037
Asset retirement obligations		465,902		453,799
Derivative financial instruments		—		1,358
Other liabilities		21,304		8,370
Total Liabilities Not Subject to Compromise		743,371		5,419,551
Liabilities subject to compromise		2,936,148		—
Total Liabilities		3,679,519		5,419,551

 
 
See accompanying Notes to Consolidated Financial Statements

93

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONSOLIDATED BALANCE SHEETS – (continued)
(In Thousands, except share information)

	June 30, 2016			June 30, 2015
Commitments and Contingencies (Note 16)
Stockholders’ Deficit
Preferred stock, $0.001 par value, 7,500,000 shares authorized at June 30, 2016 and 2015
7.25% Convertible perpetual preferred stock, 3,000 shares issued and outstanding at June 30, 2016 and 2015	$	—		$	—
5.625% Convertible perpetual preferred stock, 661,992 and 812,759 shares issued and outstanding at June 30, 2016 and 2015, respectively		1			1
Common stock, $0.005 par value, 200,000,000 shares authorized and 97,824,054 and 94,643,498 shares issued and outstanding at June 30, 2016 and 2015, respectively		488			472
Additional paid-in capital		1,845,684			1,843,918
Accumulated deficit		(4,500,258	)		(2,573,113	)
Total Stockholders’ Deficit		(2,654,085	)		(728,722	)
Total Liabilities and Stockholders’ Deficit	$	1,025,434		$	4,690,829

 
 
See accompanying Notes to Consolidated Financial Statements

94

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, except per share information)

	Year Ended June 30,
	2016			2015			2014
Revenues
Oil sales	$	546,766		$	1,052,731		$	1,104,208
Natural gas sales		69,255			117,282			135,883
Gain (loss) on derivative financial instruments		90,506			235,439			(86,968	)
Total Revenues		706,527			1,405,452			1,153,123
Costs and Expenses
Lease operating		346,073			463,535			365,747
Production taxes		1,442			8,385			5,427
Gathering and transportation		55,925			21,144			23,532
Depreciation, depletion and amortization		339,516			705,521			414,026
Accretion of asset retirement obligations		64,690			50,081			30,183
Impairment of oil and natural gas properties		2,813,570			2,421,884			—
Goodwill impairment		—			329,293			—
General and administrative expense		102,736			116,500			96,402
Total Costs and Expenses		3,723,952			4,116,343			935,317
Operating Income (Loss)		(3,017,425	)		(2,710,891	)		217,806
Other Income (Expense)
Loss from equity method investees		(10,746	)		(17,165	)		(5,231	)
Other income, net		3,596			4,176			3,298
Gain on early extinguishment of debt		1,525,596			—			—
Interest expense		(405,658	)		(323,308	)		(162,728	)
Total Other Income (Expense), net		1,112,788			(336,297	)		(164,661	)
Income (Loss) Before Reorganization Items and Income Taxes		(1,904,637	)		(3,047,188	)		53,145
Reorganization items		(14,201	)		—			—
Income (Loss) Before Income Taxes		(1,918,838	)		(3,047,188	)		53,145
Income Tax Expense (Benefit)		(87	)		(613,350	)		35,020
Net Income (Loss)		(1,918,751	)		(2,433,838	)		18,125
Preferred Stock Dividends		8,394			11,468			11,489
Net Income (Loss) Attributable to Common Stockholders	$	(1,927,145	)	$	(2,445,306	)	$	6,636
Earnings (Loss) per Share
Basic	$	(20.11	)	$	(25.97	)	$	0.09
Diluted	$	(20.11	)	$	(25.97	)	$	0.09
Weighted Average Number of Common Shares Outstanding
Basic		95,822			94,167			74,375
Diluted		95,822			94,167			74,445

 
 
See accompanying Notes to Consolidated Financial Statements

95

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
(In Thousands)

	Preferred Stock				Common Stock Shares			Common Stock			Treasury Stock Shares			Treasury Stock			Paid-in Capital			Accumulated (Deficit)			Total Stockholders’ Equity (Deficit)
	5.625%		7.25%
Balance, June 30, 2013		1		—		79,425			397			2,939			(72,663	)		1,512,311			(72,111	)		1,367,935
Common stock issued, net of direct costs		—		—		16,382			81			—			—			341,478			—			341,559
Common stock based compensation		—		—		—			—			—			—			6,711			—			6,711
Repurchase of company common stock		—		—		—			—			6,477			(170,266	)		—			—			(170,266	)
Treasury stock retired		—		—		(2,087	)		(10	)		(2,087	)		52,966			(52,956	)		—			—
Common stock reissued		—		—		—			—			(7,329	)		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	)
Net Income		—		—		—			—			—			—			—			18,125			18,125
Balance, June 30, 2014		1		—		93,720			468			—			—			1,837,462			(103,371	)		1,734,560
Common stock issued, net of direct costs		—		—		923			4			—			—			2,332			—			2,336
Common stock based compensation		—		—		—			—			—			—			4,124			—			4,124
Common stock dividends		—		—		—			—			—			—			—			(24,436	)		(24,436	)
Preferred stock dividends		—		—		—			—			—			—			—			(11,468	)		(11,468	)
Net Loss		—		—		—			—			—			—			—			(2,433,838	)		(2,433,838	)
Balance, June 30, 2015	$	1	$	—		94,643		$	472			—		$	—		$	1,843,918		$	(2,573,113	)	$	(728,722	)
Common stock issued, net of direct costs		—		—		3,181			16			—			—			430			—			446
Common stock based compensation		—		—		—			—			—			—			1,336			—			1,336
Preferred stock dividends		—		—		—			—			—			—			—			(8,394	)		(8,394	)
Net Loss		—		—		—			—			—			—			—			(1,918,751	)		(1,918,751	)
Balance, June 30, 2016	$	1	$	—		97,824		$	488			—		$	—		$	1,845,684		$	(4,500,258	)	$	(2,654,085	)

 
 
See accompanying Notes to Consolidated Financial Statements

96

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)

	Year Ended June 30,
	2016			2015			2014
Cash Flows From Operating Activities
Net income (loss)	$	(1,918,751	)	$	(2,433,838	)	$	18,125
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		339,516			705,521			414,026
Impairment of oil and natural gas properties		2,813,570			2,421,884			—
Goodwill impairment		—			329,293			—
Deferred income tax expense (benefit)		—			(614,383	)		31,379
Change in fair value of derivative financial instruments		19,163			(52,036	)		69,656
Accretion of asset retirement obligations		64,690			50,081			30,183
Loss from equity method investees		10,746			17,165			5,231
Gain on early extinguishment of debt		(1,525,596	)		—			—
Amortization and write-off of debt issuance costs and other		138,473			23,247			13,774
Deferred rent		9,154			—			—
Provision for loss on accounts receivable		3,200			—			—
Stock-based compensation		1,336			4,124			6,711
Changes in operating assets and liabilities
Accounts receivable		42,742			51,284			63,283
Prepaid expenses and other assets		(24,438	)		48,062			6,019
Settlement of asset retirement obligations		(78,273	)		(106,573	)		(57,391	)
Accounts payable and accrued liabilities		(62,187	)		(113,078	)		(55,536	)
Net Cash (Used in) Provided by Operating Activities		(166,655	)		330,753			545,460
Cash Flows from Investing Activities
Acquisitions, net of cash		(2,797	)		(301	)		(849,641	)
Capital expenditures		(111,884	)		(723,829	)		(788,676	)
Insurance payments received		8,251			3,920			1,983
Change in equity method investments		—			12,642			(34,294	)
Transfers to restricted cash		(22,136	)		(14,676	)		(325	)
Proceeds from the sale of properties		5,693			261,931			126,265
Other		(40	)		(135	)		113
Net Cash Used in Investing Activities		(122,913	)		(460,448	)		(1,544,575	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		334			2,336			3,994
Proceeds from convertible debt allocated to additional paid-in capital		—			—			63,432
Repurchase of company common stock		—			—			(184,263	)
Dividends to shareholders – common		—			(24,436	)		(34,680	)
Dividends to shareholders – preferred		(5,673	)		(11,468	)		(11,489	)
Cash restricted under revolving credit facility related to property sold		—			(21,000	)		—
Proceeds from long-term debt		1,121			2,586,572			3,420,873
Payments on long-term debt		(227,884	)		(1,747,849	)		(2,079,485	)
Payment of debt assumed in acquisition		(25,187	)		—			—
Fees related to debt extinguishment		(3,526	)		—			—
Debt issuance costs		(2,163	)		(43,352	)		(33,461	)
Other		(1,044	)		(66	)		—
Net Cash (Used in) Provided by Financing Activities		(264,022	)		740,737			1,144,921
Net (Decrease) Increase in Cash and Cash Equivalents		(553,590	)		611,042			145,806
Cash and Cash Equivalents, beginning of period		756,848			145,806			—
Cash and Cash Equivalents, end of period	$	203,258		$	756,848		$	145,806

 
 
See accompanying Notes to Consolidated Financial Statements

97

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 1 — Organization

Nature of Operations

Energy XXI Ltd was incorporated in Bermuda on July 25, 2005. References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI Ltd and its wholly-owned subsidiaries. With our principal operating subsidiary headquartered in Houston, Texas, we have historically 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”). We were listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “EXXI” prior to the suspension of our common stock from trading at the opening of business on April 25, 2016, in connection with the commencement of the chapter 11 bankruptcy proceedings described below. Our common stock resumed trading on the OTC Markets Group Inc.’s OTC Pink (the “OTC Pink”) under the symbol “EXXIQ” on April 25, 2016.

Bankruptcy Proceedings and Restructuring Support Agreement

On April 14, 2016 (the “Petition Date”), Energy XXI Ltd, Energy XXI Gulf Coast, Inc., an indirect wholly-owned subsidiary of the Company (“EGC”), EPL Oil & Gas, Inc., an indirect wholly-owned subsidiary of Energy XXI Ltd (“EPL”) and certain other subsidiaries of Energy XXI Ltd (together with Energy XXI Ltd, the “Debtors”) (excluding Energy XXI GIGS Services, LLC which leases a subsea pipeline gathering system located in the shallow GoM Shelf and storage and onshore processing facilities on Grand Isle, Louisiana, Energy XXI Insurance Limited through which certain insurance coverage for its operations is obtained by the Company, Energy XXI (US Holdings) Limited, Energy XXI International Limited, Energy XXI Malaysia Limited and Energy XXI M21K, LLC, (together, the “Non-Debtors”)) filed voluntary petitions for reorganization (the petitions collectively, the “Bankruptcy Petitions”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) seeking relief under the provisions of chapter 11 of Title 11 (“Chapter 11”) of the United States Bankruptcy Code (the “Bankruptcy Code”). The Debtors’ Chapter 11 cases (collectively, the “Chapter 11 Cases”) are being jointly administered under the caption “In re: Energy XXI Ltd, et al., Case No. 16-31928.” The Debtors continue to operate their businesses and manage their assets as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Concurrently with the filing of the Bankruptcy Petitions and to streamline the business operations and organization structure following the emergence from the Chapter 11 Cases, Energy XXI Ltd filed a petition commencing an official dissolution proceeding under the laws of Bermuda before the Supreme Court of Bermuda (the “Bermuda Proceedings”). On April 15, 2016, John C. McKenna was appointed as provisional liquidator by the Supreme Court of Bermuda. The Bermuda Proceeding is a limited ancillary proceeding under which dissolution of Energy XXI Ltd will be completed following the confirmation of the bankruptcy plan by the Bankruptcy Court, accordingly, the Bankruptcy Court retains primary jurisdiction over Energy XXI Ltd during the Chapter 11 proceedings. See Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources” for a discussion of the Chapter 11 Cases. On June 3, 2016, the Bermuda Court granted the Debtors’ request to adjourn the Bermuda Proceeding through November 4, 2016.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. However, the Chapter 11 Cases and sustained depressed commodity prices raise substantial doubt about our ability to continue as a going concern.

98

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 1 — Organization  – (continued)

The consolidated financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern.

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements

Principles of Consolidation and Reporting.  The accompanying consolidated financial statements include the accounts of Energy XXI Ltd 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 accounts and transactions are 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 (loss), consolidated stockholders’ equity or consolidated cash flows. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

For periods subsequent to filing the Bankruptcy Petitions, we have prepared our consolidated financial statements in accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Pre-petition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

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. Other items subject to estimates and assumptions include fair value estimates used in accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; valuation of derivative financial instruments; reorganization items and liabilities subject to compromise, among others. Accordingly, our accounting estimates require the 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 differences 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 trusts as required by certain contractual arrangements and disposition transactions. Amounts on deposit in trust accounts 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

99

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements  – (continued)

specific identification method. As of June 30, 2016, our allowance for doubtful accounts was $3.2 million. As of June 30, 2015, 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 natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of (i) a determination as to whether there are any proved reserves related to the properties, (ii) a determination that the capital costs associated with the development of these properties will not be available, or (iii) ratably over a period of time of not more than four years.

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. Estimated 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, 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 over total proved reserves.

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

100

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements  – (continued)

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 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 the year ended June 30, 2014 in connection with the acquisition of EPL and was recorded to our oil and gas reporting unit. At December 31, 2014, we conducted a qualitative goodwill impairment assessment and after assessing the relevant events and circumstances, we determined that performing a quantitative goodwill impairment test was necessary. Therefore, we performed steps one and two of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 5 — “Goodwill” for more information.

Derivative Instruments.  We have historically used various derivative instruments including crude oil and natural gas 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. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Any premiums paid or financed on derivative financial instruments are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or financed. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations.

101

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements  – (continued)

Debt Issuance Costs.  Costs incurred in connection with the issuance of long-term debt are capitalized and are amortized to interest expense generally over the scheduled maturity of the debt utilizing the interest method. As a result of covenant violations that existed at March 31, 2016 that were not cured prior to the filing of the Bankruptcy Petitions, all of our outstanding indebtedness was classified as current in the consolidated balance sheet at March 31, 2016. As a result, except for amounts related to the revolving credit facility with respect to which we currently believe that it is probable that we may enter into a potential restructuring agreement, we accelerated the amortization of the remaining debt issuance costs related to our outstanding indebtedness, fully amortizing those costs as of March 31, 2016.

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 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 when the product is delivered at the contracted sales price, title is transferred and collectability is reasonably assured. The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. The amounts of imbalances were not material at June 30, 2016 and 2015.

General and Administrative Expense.  Under the full cost method of accounting, the portion of our general and administrative expense that is directly identified with our acquisition, exploration and development activities is capitalized as part of our oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to support those employees 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, 2016, 2015 and 2014 was $17.0 million, $49.2 million, and $64.5 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

102

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements  – (continued)

development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code of 1986, as amended (“IRC”) 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. In light of the results of operations for fiscal year 2015 (heavily affected by impairments) we recorded an increase in our valuation allowance of $356.8 million resulting in a balance of $379.3 million at June 30, 2015. Due to continuing losses, we recorded an additional valuation allowance of $650 million resulting in a balance of $1,029.3 at June 30, 2016. We recorded this increase to our valuation allowance against our net deferred tax assets due to our judgment that our existing U.S. federal and 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.

Earnings per Share.  Basic earnings (loss) 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 potential dilution using the treasury stock method. Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of the assumed conversion of our convertible preferred stock and other potential shares of common stock.

Recent Accounting Pronouncements.  In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. In August 2015, the FASB issued ASU 2015-14 which deferred the effective date of ASU 2014-09. With the one-year deferral, ASU 2014-09 is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted.

In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. Our early adoption of ASU 2014-15 during the quarter ended December 31, 2015 impacted our disclosures but had no effect on our consolidated financial position, results of operations or cash flows.

103

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements  – (continued)

In April 2015, the FASB issued ASU No. 2015-03, Interest — Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. In June 2015, the FASB issued ASU 2015-15 as an amendment to this guidance to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements. The SEC staff stated that they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.

The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued. The guidance will be applied on a retrospective basis. As a result of adopting ASU 2015-15, debt issuance costs will be presented in our consolidated balance sheets as a reduction in the carrying amount of the related debt liability, although we are continuing to evaluate the impact of ASU 2015-15 as it relates to debt issuance costs associated with line-of-credit arrangements.

In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred taxes on the balance sheet by requiring classification of all deferred tax items as noncurrent including valuation allowances by jurisdiction. ASU 2015-17 is effective for public entities for annual periods beginning after December 15, 2016, and interim periods within those annual reporting periods. Early adoption is permitted as of the beginning of any interim or annual reporting period. Our early adoption of ASU 2015-17 during the quarter ended December 31, 2015 had no effect on our consolidated financial position, results of operations or cash flows other than presentation.

In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB Accounting Standards Codification and creating Topic 842, Leases. The guidance in this ASU supersedes Topic 840, Leases. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the provisions of this new standard and assessing the impact it may have on our consolidated financial position, results of operations or cash flows.

In June 2016, the FASB issued ASU No. 2016-13, Credit Losses, Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). ASU 2016-13 significantly changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace today’s incurred loss approach with an expected loss model for instruments measured at amortized cost. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. This ASU is effective for public entities for annual and interim periods beginning after December 15, 2019. Early adoption is permitted for all entities for annual periods beginning after December 15, 2018, and interim periods therein. We have not yet determined the effect of this standard on our consolidated financial position, results of operations or cash flows.

104

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources

Chapter 11 Proceedings and Restructuring Support Agreement

On the Petition Date, the Debtors filed the Bankruptcy Petitions seeking relief under Chapter 11 of the Bankruptcy Code. Since then, the Debtors have operated their businesses and managed their assets as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

On April 11, 2016, the Debtors entered into a Restructuring Support Agreement (as amended, the “Restructuring Support Agreement”) with certain holders (the “Second Lien Noteholders”) of EGC’s 11.0% Senior Secured Second Lien Notes due 2020 (the “Second Lien Notes”), providing that the Second Lien Noteholders party thereto will support a restructuring of the Debtors, subject to the terms and conditions of the Restructuring Support Agreement.

On July 15, 2016, the Bankruptcy Court entered the Order (A) Approving the Disclosure Statement and the Form and Manner of Service Related Thereto, (B) Setting Dates for the Objections Deadline and Hearing Related to Confirmation of the Plan, and (C) Granting Related Relief [Docket No. 805], approving the adequacy of the Third Amended Disclosure Statement for the Debtors’ Proposed Joint Chapter 11 Plan of Reorganization [Docket No. 809] (the “Disclosure Statement”) and related solicitation materials, thereby authorizing the Debtors to solicit votes to accept or reject the Debtors’ Proposed Joint Chapter 11 Plan of Reorganization [Docket No. 810] from applicable creditor constituencies.

On September 8, 2016, a meeting (the “September 8 Meeting”) occurred between certain representatives of the Debtors, certain Second Lien Noteholders, the Official Committee of Unsecured Creditors (the “UCC”), certain holders of unsecured indebtedness issued by EGC (the “Ad Hoc EGC Group”) and certain holders of unsecured indebtedness issued by EPL (the “Ad Hoc EPL Group”), during which the Second Lien Noteholders made an offer to the Debtors, the UCC, the Ad Hoc EGC Group and advisors to Ad Hoc EPL Group to modify certain terms of the Debtor’s July 15, 2016 proposed plan of reorganization (the “September 8 Second Lien Offer”). The UCC, the Ad Hoc EGC Group and the Ad Hoc EPL Group did not accept the September 8 Second Lien Offer, submit a counter-offer or enter into any negotiations with the Debtors or the Second Lien Noteholders following the receipt of the September 8 Second Lien Offer during the September 8 Meeting. However, on September 12, 2016, the Debtors received a proposal for an alternative chapter 11 plan of reorganization from the Ad Hoc EGC Group and the Ad Hoc EPL Group, which the Debtors’ are in the process of reviewing with their advisors.

Following subsequent negotiations between the Debtors and the Second Lien Noteholders, on September 13, 2016, the Debtors and the Second Lien Noteholders entered into the Fifth Amendment to the Restructuring Support Agreement (the “Fifth RSA Amendment”), which provided, among other things, that the Debtors file an amended Plan to reflect the terms of the Fifth RSA Amendment. The boards of directors of the Company, EGC and EPL, including all independent directors, approved the entry into the Fifth RSA Amendment and the term sheet attached thereto. Subject to approval by the Bankruptcy Court, the terms of the restructuring of the Debtors’ as contemplated in the Fifth RSA Amendment, were included in the Debtors’ Amended Proposed Joint Chapter 11 Plan of Reorganization [Docket No. 1307], filed September 14, 2016, which includes such changes and modifications contemplated by the Fifth RSA Amendment (as may be amended, modified, or supplemented from time to time, the “Plan”).

On September 16, 2016, the Debtors filed an initial form of supplement (the “DS Supplement”) to the Disclosure Statement, which summarized the modifications to the Plan contemplated by the Fifth RSA Amendment. The Plan as amended now supersedes the September 8 Second Lien Offer. The Debtors sought approval of the adequacy of the DS Supplement and related solicitation materials at a hearing held before the Bankruptcy Court on September 22, 2016, following which the Bankruptcy Court approved the DS Supplement in its Order (A) Approving the Adequacy of the Supplement to the Debtors’ Third Amended

105

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

Disclosure Statement Setting Forth Modifications to the Debtors’ Proposed Joint Chapter 11 Plan of Reorganization and the Continued Solicitation of the Plan and (B) Granting Related Relief [Docket No. 1416] on September 25, 2016. The Debtors will distribute the DS Supplement and related solicitation materials to creditors entitled to vote on the Plan to enable such creditors to vote on the Plan changes.

In an effort to consensually resolve outstanding disputes among the parties in interest, representatives for the Debtors, the First Lien Agent, the Second Lien Noteholders, the UCC and its members, the Equity Committee, the Ad Hoc EGC Group, and the Ad Hoc EPL Group have agreed to participate in a confidential and non-binding mediation process, as discussed on the record at a hearing before the Bankruptcy Court on September 13, 2016. On September 16, 2016, the Bankruptcy Court appointed Judge Leif Clark as the mediator. Mediation is scheduled to commence on September 28, 2016.

The hearing to consider confirmation of the Plan is currently set for October 17, 2016, but may change depending upon the outcome of, among other things, mediation and other developments in the Chapter 11 Cases.

As amended, the Restructuring Support Agreement provides, among other things, that:

• The dissolution of Energy XXI Ltd will be completed under the laws of Bermuda following the confirmation of the Plan by the Bankruptcy Court, and, given that it is unlikely to have assets available for distribution, existing equity holders would receive no distributions in respect of that equity in that dissolution.

• The Debtors, on behalf of the holders of claims (the “First Lien Claims”) arising on account of the Company’s Second Amended and Restated First Lien Credit Agreement (as amended, the “First Lien Credit Agreement,” or “Revolving Credit Facility”) and subject to further negotiations with the lenders under the Revolving Credit Facility (the “Lenders”), will use their best efforts to ensure that at emergence from Chapter 11, the amount drawn under the Revolving Credit Facility either (i) remains outstanding or (ii) is refinanced with a new facility with terms acceptable to the Second Lien Noteholders party to the Restructuring Support Agreement (the “Restructuring Support Parties”) who hold, in aggregate, at least 66.6% in principal amount of the Second Lien Notes Claims (as defined below) held by the Restructuring Support Parties (the “Majority Restructuring Support Parties”); provided, however that (a) $227.8 million of letters of credit usage remains outstanding and (b) other terms, including a borrowing base redetermination holiday, are acceptable to the Debtors and the Majority Restructuring Support Parties. If the Debtors are unable to obtain the foregoing treatment of the First Lien Claims, then the Debtors will use their best efforts to obtain treatment acceptable to the Debtors and the Majority Restructuring Support Parties.

• Holders of claims against any Debtor (other than an administrative claim or a secured tax claim) entitled to priority in right of payment under section 507(a) of the Bankruptcy Code, to the extent such claim has not already been paid during the Chapter 11 Cases will receive either: (i) payment in full in cash equal to the full allowed amount of such claim or (ii) such other treatment as may otherwise be agreed to by such holder, the Debtors, and the Majority Restructuring Support Parties.

• Holders of secured claims (other than a priority tax claim, First Lien Claim, or Second Lien Notes Claim) will receive, at the Debtors’ election and with the consent of the Majority Restructuring Support Parties, either: (i) cash equal to the full allowed amount of such claim, (ii) reinstatement of such holder’s claim, (iii) the return or abandonment of the collateral securing such claim to such holder, or (iv) such other treatment as may otherwise be agreed to by such holder, the Debtors, and the Majority Restructuring Support Parties.

106

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

• Holders of claims relating to the Second Lien Notes (the “Second Lien Notes Claims”) will receive their pro rata share of (i) 87.8% of common stock (the “New Equity”) in the reorganized company (the “New Entity”) on account of such Second Lien Notes Claims, subject to dilution from the issuance of New Equity in connection with the long-term management incentive plan for the reorganized Debtors (the “Management Incentive Plan”) and (ii) the New Equity allocated to the Second Lien Notes Claims in connection with the EGC Intercompany Note Trust (as defined below), if applicable, and subject to dilution by the Management Incentive Plan;

• Holders of claims relating to the unsecured EGC notes (the “EGC Unsecured Notes Claims”) will receive their pro rata share of (i) 0.4% of the New Equity, subject to dilution from the Management Incentive Plan and (ii) the New Equity allocated to the EGC Unsecured Notes Claims in connection with the EGC Intercompany Note Trust, if applicable, and subject to dilution by the Management Incentive Plan;

• Holder of claims relating to the unsecured EPL notes (the “EPL Unsecured Notes Claims”) will receive their pro rata share of the New Equity allocated to the EPL Unsecured Notes Claims in connection with the EGC Intercompany Note Trust, if applicable;

• Holders of claims relating to the Company’s 3.0% Senior Convertible Notes will receive their pro rata share of 0.2% of the New Equity, subject to dilution from the Management Incentive Plan;

• As of the date that the Debtors must consummate the transactions contemplated by the Plan (the date of such consummation, the “Effective Date”), 11.6% of the New Equity will be deposited into a trust (the “EGC Intercompany Note Trust”) and to be distributed among the Second Lien Notes Claims, the EGC Unsecured Notes Claims and the EPL Unsecured Notes Claims pursuant to a final order entered by the Bankruptcy Court resolving any causes of action, as well as all applicable defenses and counterclaims, challenging: (a) the validity and enforceability of that certain promissory note in the principal amount of $325.0 million between EPL, as the maker, and EGC, as the payee, (the “EGC Intercompany Note”) on the grounds of: preference; recharacterization; equitable subordination; and/or fraudulent transfer; and (b) the validity and enforceability of the intercompany payables between EGC and EPL other than the EGC Intercompany Note; provided, however, that the distribution under the EGC Intercompany Note Trust to the holders of Second Lien Notes Claims will not exceed 93.2%, (ii) the distribution to the holders of EGC Unsecured Notes Claims will not exceed 6.6%, (iii) the distribution to the holders of EPL Unsecured Notes Claims will not exceed 11.6% and (iv) $500,000 cash will be deposited in equal amounts in two separate, non-interest bearing escrow accounts to fund the respective fees and expenses of the advisors of the trustee representing EGC and the trustee representing EPL in connection with the EGC Intercompany Note Trust;

• The Management Incentive Plan will be capped at 5%;

• John D. Schiller, Jr. will continue as the New Entity’s Chief Executive Officer and a member of its board of directors: and

• The Debtors will negotiate the terms and conditions of an amended and restated employment agreement with Mr. Schiller as Chief Executive Officer of the reorganized company, which terms and conditions shall be subject to the prior written consent of the Majority Restructuring Support Parties.

107

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

Milestones

As amended, the Restructuring Support Agreement also contains the following proposed milestones (the “Milestones”) for progress in the Chapter 11 proceedings:

• no later than October 7, 2016, the Bankruptcy Court shall have commenced the hearing to consider confirmation of the Plan (the “Confirmation Hearing”);

• no later than October 13, 2016, the Bankruptcy Court shall have entered an order authorizing the assumption of the Restructuring Support;

• no later than October 13, 2016, the Bankruptcy Court shall have entered the confirmation order with respect to the Plan; and

• no later than October 27, 2016, the Debtors shall consummate the transactions contemplated by the Plan, it being understood that the satisfaction of the conditions precedent to the Effective Date (as set forth in the Plan) shall be conditions precedent to the occurrence of the Effective Date.

The Confirmation Hearing is currently set for October 17, 2016, but may change depending upon the outcome of, among other things, mediation and other developments in the Chapter 11 Cases. The Debtors anticipate entering into a further Restructuring Support Agreement amendment to modify the Milestones to reflect this new timeline in the near term.

The Majority Restructuring Support Parties have the right, but not the obligation, to terminate their obligations under the Restructuring Support Agreement upon the failure of the Debtors to meet any of the Milestones unless (i) such failure is the direct result of any act, omission, or delay on the part of any Restructuring Support Party in violation of its obligations under the Restructuring Support Agreement or (ii) such Milestone is extended with the express prior written consent of the Majority Restructuring Support Parties.

Reorganization Process

On the Petition Date, the Bankruptcy Court issued certain additional interim and final orders with respect to the Debtors’ first-day motions and other operating motions that allow the Debtors to operate their businesses in the ordinary course. The first-day motions provided for, among other things, the payment of certain pre-petition employee and retiree expenses and benefits, the use of the Debtors’ existing cash management system, the payment of certain pre-petition amounts to certain critical vendors, the ability to pay certain pre-petition taxes and regulatory fees, and the payment of certain pre-petition claims owed on account of insurance policies and programs.

Subject to certain exceptions under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover, collect or secure a pre-petition claim. Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’ property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay under Section 362 of the Bankruptcy Code.

Under Section 365 and other relevant sections of the Bankruptcy Code, the Debtors’ may assume, assume and assign, or reject certain executory contracts and unexpired leases, including leases of real property and equipment, subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves Debtors of performing their future obligations

108

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

under such executory contract or unexpired lease but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach. On July 8, 2016, the Debtors filed a motion for an order to extend time to assume or reject unexpired leases of nonresidential real property from August 15, 2016 through and including November 14 (the “Motion to Extend Time to Assume or Reject Unexpired Leases”). On July 27, 2016 the Bankruptcy Court entered an order approving the Motion to Extend Time to Assume or Reject Unexpired Leases. On July 26, 2016, the Debtors filed a motion to reject executory contracts, for certain contracts contained therein. On August 23, 2016, the Bankruptcy Court granted the Debtors’ motion in the Order (A) Authorizing the Debtors to Reject Certain Executory Contracts Effective Nunc Pro Tunc to July 26, 2016, and (B) Granting Related Relief [Docket No. 1133].

A Chapter 11 plan (including the Plan) determines the rights and satisfaction of claims and interests of various creditors and security holders and is subject to the ultimate outcome of negotiations and the Bankruptcy Court’s decisions through the date on which a Chapter 11 plan (including the Plan) is confirmed. The Plan currently provides mechanisms for settlement of the Debtors’ pre-petition obligations, changes to certain operational cost drivers, treatment of our existing equity holders, potential income tax liabilities and certain corporate governance and administrative matters pertaining to the reorganized New Entity. The Plan remains subject to revision based upon discussions with the Debtors’ creditors, including the Lenders under the Revolving Credit Facility and holders of the EGC Unsecured Notes Claims, holders of the EPL Unsecured Notes Claims, and holders of claims relating to Energy XXI’s 3.0% Senior Convertible Notes, and other interested parties, and thereafter in response to any Plan objections and the requirements of the Bankruptcy Code or the Bankruptcy Court. There can be no assurance that the Debtors will be able to secure Bankruptcy Court approval of the Plan or any other Chapter 11 plan or that the Plan or any other Chapter 11 plan will be accepted by the classes of creditors entitled to vote thereon.

Under the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before stockholders are entitled to receive any distribution or retain any property under a Chapter 11 plan (including the Plan). The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation of a Chapter 11 plan (including the Plan). No assurance can be given as to what values, if any, will be ascribed to each of these constituencies or what types or amounts of distributions, if any, they would receive. A Chapter 11 plan (including the Plan) could result in holders of certain liabilities and/or securities, including common stock, receiving no distribution on account of their interests. Because of such possibilities, there is significant uncertainty regarding the value of our liabilities and securities, including our common stock. At this time, there is no assurance we will be able to restructure as a going concern or successfully propose or implement a Chapter 11 plan (including the Plan).

In accordance with the Milestones, we filed the Disclosure Statement, Plan, and a motion seeking, among other things, (A) approval of the Disclosure Statement, (B) approval of procedures for soliciting, receiving, and tabulating votes on the Plan and for filing objections to the Plan, and (C) to schedule the Confirmation Hearing on May 20, 2016. Subsequently, we filed amended versions of the Disclosure Statement and Plan on June 14, 2016, July 13, 2016, September 14, 2016 and again on September 23, 2016. The amendments reflected, among other things, substantial additional disclosures requested by certain creditor constituencies. The amendments also reflected changes to the proposed treatment of certain classes under the Plan made in conjunction with or as a result of amendments to the Restructuring Support Agreement.

The Bankruptcy Court entered an order approving the Disclosure Statement with respect to the Plan on July 15, 2016, and we filed the solicitation version of the Disclosure Statement on July 18, 2016. Under the Bankruptcy Code, only holders of claims or interests in “impaired” classes, as defined under section 1124 of the Bankruptcy Code, are entitled to vote on a plan. Ballots to vote to accept or reject the plan were distributed to creditors entitled to vote on the plan between July 22, 2016 and July 25, 2016. On September 22, 2016, the Bankruptcy Court held a hearing to consider the adequacy of the DS Supplement

109

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

reflecting certain changes to the Plan. The Bankruptcy Court approved the DS Supplement on September 25, 2016. The Debtors will distribute the DS Supplement and related solicitation materials to creditors entitled to vote on the Plan, to enable creditors to vote on the Plan as amended. The deadline to submit a vote to accept or reject the Plan is October 13, 2016 at 5:00 P.M., central time. The hearing to consider confirmation of the Plan is scheduled for October 17, 2016 before the Bankruptcy Court.

Even if our Plan meets other requirements under the Bankruptcy Code, creditors may not vote in favor of our Plan, and certain parties in interest may file objections to the Plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Further, even if no objections are filed and the requisite acceptances of our Plan are received from creditors entitled to vote on the Plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Plan.

Liabilities Subject to Compromise

Liabilities subject to compromise represent liabilities incurred prior to the commencement of the bankruptcy proceedings which may be affected by the Chapter 11 process. These amounts represent the Company’s allowed claims and its best estimate of claims expected to be allowed which will be resolved as part of the bankruptcy proceedings. Such claims remain subject to future adjustments. Adjustments may result from negotiations, actions of the Bankruptcy Court, determination as to the value of any collateral securing claims, or other events. Differences between liability amounts estimated by the Company and claims filed by creditors are being investigated and the Bankruptcy Court will make a final determination of the allowable claims. Liabilities subject to compromise consist of the following (certain intercompany liabilities as well as the 9.25% Senior Notes and 8.25% Senior Notes, which repurchased and held by EGC, which will also be resolved as part of the Chapter 11 Cases are not reflected below) (in thousands):

	June 30, 2016
Debt
11.0% Senior Secured Second Lien Notes due 2020	$	1,450,000
8.25% Senior Notes due 2018		213,677
6.875% Senior Notes due 2024		143,993
3.0% Senior Convertible Notes due 2018		363,018
7.5% Senior Notes due 2021		238,071
7.75% Senior Notes due 2019		101,077
9.25% Senior Notes due 2017		249,452
4.14% Promissory Note due 2017		4,006
Capital lease obligations		714
Total debt		2,764,008
Accounts payable		38,202
Accrued liabilities		133,938
Total liabilities subject to compromise	$	2,936,148

Interest Expense

The Debtors have discontinued recording interest on debt classified as liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $52.8 million, representing interest expense from the Petition Date through June 30, 2016.

110

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

Executory Contracts

Under the Bankruptcy Code, the Debtors have the right to assume, amend and assume, or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to contracts rejected by a debtor may file proofs of claim against that debtor’s estate for damages.

On May 28, 2016, the Debtors filed the Plan supplement, which included a schedule of assumed contracts and a schedule of rejected contracts, and since then have filed amended plan supplements and additional motions with respect to assumed and rejected contracts. The Debtors continue to review and analyze their contractual obligations to move contracts from the schedule of assumed contracts to the schedule of rejected contracts or from the schedule of rejected contracts to the schedule of amended contracts.

Potential Claims

The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing.

Certain holders of pre-petition claims are required to file proofs of claim by a certain date (the “Bar Date”). As of September 26, 2016, 1,578 claims totaling approximately $40,500 million had been filed with the Bankruptcy Court against the Debtors. It is possible that claimants will file amended claims in the future, including claims amended to assign values to claims originally filed with no designated value. Through the claims resolution process, we have identified, and we expect to continue to identify, claims that we believe should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. We will file objections with the Bankruptcy Court as necessary for claims we believe should be disallowed. Claims we believe are allowable are reflected in “Liabilities Subject to Compromise” in the Consolidated Balance Sheets.

Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In light of the number of claims filed, the claims resolution process will take additional time to complete, and it may continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

Reorganization Items

Reorganization items represent the direct and incremental costs of being in bankruptcy, such as professional fees. Reorganization items consist of the following for the year ended June 30, 2016 (in thousands) of which $12.1 million remains accrued as of June 30, 2016:

	Year Ended June 30, 2016
Professional fees	$	14,201
Total reorganization items	$	14,201

111

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

Debtors Condensed Combined Financial Statements

Condensed combined financial statements of the Debtors are set forth below. These condensed combined financial statements exclude the financial statements of the Non-Debtors. Transactions and balances of receivables and payables between Debtors are eliminated in consolidation. However, the Debtors’ condensed combined balance sheet includes receivables from related Non-Debtors and payables to related Non-Debtors.

CONDENSED COMBINED BALANCE SHEET
 
(In Thousands)

	June 30, 2016
ASSETS
Current assets, net	$	373,447
Property and equipment, net		620,230
Restricted cash		25,548
Other assets		29,939
Total Assets	$	1,049,164
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities	$	255,490
Long-term liabilities		478,803
Accumulated losses in excess of equity investments		2,549,483
Liabilities subject to compromise		3,339,069
Stockholders’ deficit		(5,573,681	)
Total Liabilities and Stockholders’ Deficit	$	1,049,164

CONDENSED COMBINED STATEMENT OF OPERATIONS
 
(In Thousands)

	Year Ended June 30, 2016
Revenues	$	693,955
Costs and Expenses
Impairment of oil and gas properties		2,813,570
Other costs and expenses		944,107
Total costs and expenses		3,757,677
Operating loss		(3,063,722	)
Other Income (Expense)
Other expense, net		(21,199	)
Gain on early extinguishment of debt		1,525,596
Interest expense		(405,658	)
Total Other Income, net		1,098,739
Net Loss Before Reorganization Items		(1,964,983	)
Reorganization items		(14,201	)
Net Loss Before Income Taxes		(1,979,184	)
Income tax benefit		(87	)
Net Loss	$	(1,979,097	)

112

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

CONDENSED COMBINED STATEMENT OF CASH FLOWS
 
(In Thousands)

	Year Ended June 30, 2016
Cash flow used in operating activities	$	(167,129	)
Cash flow used in investing activities		(122,386	)
Cash flow used in financing activities		(264,022	)
Net decrease in cash and cash equivalents		(553,537	)
Cash and cash equivalents at beginning of period		755,794
Cash and cash equivalents at end of period	$	202,257

Liquidity and Capital Resources

As of June 30, 2016, we had cash and cash equivalents of approximately $203.3 million and no available borrowing capacity under our Revolving Credit Facility. As of June 30, 2016, the total carrying value of our indebtedness was $2,863.8 million and was currently due as a result of filing the Bankruptcy Petitions which constituted an event of default with respect to our existing debt obligations. Our indebtedness was comprised of $99.8 million of secured indebtedness outstanding consisting of $99.4 million under our Revolving Credit Facility and $0.4 million of payment “in-kind” (“PIK”) interest under Exit Facility Term Sheet with the lenders under First Lien Credit Agreement (the “Exit Facility Term Sheet”), $1,450 million of Second Lien Notes, $4.7 million in other secured indebtedness and $1,309.3 million of unsecured notes.

Subject to certain exceptions under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the filing of the Bankruptcy Petitions. Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’ property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

The Bankruptcy Court has approved payment of certain pre-petition obligations, including payments for employee wages, salaries and certain other benefits, customer programs, taxes, utilities, insurance, surety bond premiums as well as payments to critical vendors and possessory lien vendors. Despite the liquidity provided by our existing cash on hand, our ability to maintain normal credit terms with our suppliers may become impaired. We may be required to pay cash in advance to certain vendors and may experience restrictions on the availability of trade credit, which would further reduce our liquidity. If liquidity problems persist, our suppliers could refuse to provide key products and services in the future. In addition, due to the public perception of our financial condition and results of operations, in particular with regard to our potential failure to meet our debt obligations, some vendors could be reluctant to enter into long-term agreements with us.

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees in connection with our Chapter 11 proceedings as disclosed in the table under the caption Reorganization Items above and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. The Company believes it has sufficient liquidity, including its cash on hand as of June 30, 2016 and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 proceedings for minimum operating and capital expenditures and for working capital purposes and excluding principal and interest payments on our

113

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

outstanding debt. As such, the Company expects to pay vendor, royalty and surety obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders approving such payments. The Company does not intend to seek debtor-in-possession financing at this time.

As contemplated by the Exit Facility Term Sheet with the Lenders under the Revolving Credit Facility, which is subject to change and to be considered in connection with Plan confirmation, we anticipate that the reorganized company (the “New Entity”) will enter into new exit financing (the “Exit Facility”) comprised of the following tranches: (i) conversion of the remaining drawn amount, net of related restricted cash, of approximately $69 million plus accrued default interest into a new term loan (the “Exit Term Loan”) with the New Entity and (ii) the conversion of the former EGC tranche of the Revolving Credit Facility into a new EGC sub-facility (the “EGC Facility”). The Exit Term Loan will have a maturity of three years with an annual interest rate of LIBOR plus 4.5%, payable monthly. The EGC Facility will have a maturity of three years with an annual interest rate of 4.5%, payable on a schedule consistent with the Revolving Credit Facility. Existing letters of credit may be renewed or replaced (in each case, in an outstanding amount not to exceed the outstanding amount of the existing letter of credit). Availability under the Exit Facility will be permanently reduced by one-half of the amount of any reduction resulting from replacement or cancellation of an outstanding letter of credit. Any amount of cancellation or reduction that does not permanently reduce capacity will be available for the New Entity to fund new liquidity (the “New Funded Debt”). Such New Funded Debt in excess of $25 million will be subject to borrowing base redetermination. Pursuant to the Exit Facility, the New Entity and its subsidiaries will be subject to certain financial maintenance covenants and, in the case of the Exit Term Loan, amortization covenants.

In addition, upon emergence from the Chapter 11 Cases, we are required under the Exit Facility to have liquidity of at least $90 million per the Exit Facility Term Sheet with the Lenders under our First Lien Credit Agreement (the “Minimum Cash Balance”). While we expect the Exit Facility and Minimum Cash Balance described above to be available under the Plan, we may not be able to access adequate funding in the future as there will be no remaining available borrowing capacity contemplated under the Exit Facility, and there is no certainty that any new capacity will be created or that the Exit Facility may be refinanced on economically advantageous terms, and the Minimum Cash Balance and cash from operations may not be sufficient to otherwise fund our operations.

We believe that our capital resources from existing cash balances, borrowings under any new capacity created under our Exit Facility, and anticipated cash flow from operating activities will be adequate to execute our corporate strategies.

Given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our operations, our liquidity needs could be significantly higher than we currently anticipate. Our ability to maintain adequate liquidity through the reorganization process and beyond depends on our ability to successfully implement the Plan (or another Chapter 11 plan), successful operation of our business, and appropriate management of operating expenses and capital spending. Our anticipated liquidity needs are highly sensitive to changes in each of these and other factors. If we are unable to meet our liquidity needs, we may have to take other actions to seek additional financing to the extent available or we could be forced to consider other alternatives to maximize potential recovery for the creditors, including possible sale of the Company or certain material assets pursuant to Section 363 of the Bankruptcy Code, or a liquidation under Chapter 7 of the Bankruptcy Code.

The Bankruptcy Court has entered a final order approving the Debtors’ use of cash collateral subject to the terms and conditions of such order, the Restructuring Support Agreement, and the cash collateral budget, to use cash collateral for a certain period from the Petition Date and the Debtors have agreed to pursue the confirmation and implementation of the Plan within that certain period. The Debtors’ use of cash collateral

114

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 3 — Chapter 11 Proceedings, Liquidity and Capital Resources  – (continued)

is critical to their ability to operate during the course of the Chapter 11 Cases, to remain current on their post-petition operating costs, to pursue a reorganization pursuant to the Plan and to emerge successfully as a going concern from the Chapter 11 Cases.

Note 4 — Acquisitions and Dispositions

Acquisition of interest in M21K

On August 11, 2015, pursuant to a stock purchase agreement (the “M21K Purchase Agreement”) between Energy XXI M21K, LLC (“EXXI M21K”), in which we owned 20% interest, and Energy XXI GOM, LLC, an indirect wholly owned subsidiary of Energy XXI, we acquired all of the remaining equity interests of M21K, LLC (“M21K”) for consideration consisting of the assumption of all obligations and liabilities of M21K including approximately $25.2 million associated with M21K’s first lien credit facility, which was required to be paid at closing (the “M21K Acquisition”). The sellers retained certain overriding royalty interests applicable only to the extent that production proceeds during any calendar month average in excess of $65.00/Bbl WTI and $3.50/MMbtu Henry Hub and limited to a term of four years or an aggregate amount of $20 million, whichever occurs earlier. In addition, with respect to the Eugene Island 330 and South Marsh Island 128 fields, in the event we sell our interest in one or both of these fields, the overriding royalty interests with respect to such sold field shall terminate; provided, however if such sale occurs within four years of the effective date of the M21K Purchase Agreement and the consideration received for such sale is greater than the allocated value for such field as specified in the M21K Purchase Agreement, then we are obligated to pay an amount equal to 20% of the portion of the consideration received in excess of the specified allocated value of such field. Prior to this transaction which was effective as of August 1, 2015, we had owned a 20% interest in M21K through our investment in EXXI M21K. See Note 7 — Equity Method Investments.

The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their estimated fair values on August 11, 2015 (in thousands):

Oil and natural gas properties – evaluated	$	73,910
Oil and natural gas properties – unevaluated		39,278
Asset retirement obligations		(66,700	)
Net working capital*		(21,301	)
Fair value of debt assumed		(25,187	)
Cash paid	$	—

* Net working capital includes approximately $1.0 million in cash.

EPL Acquisition

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

115

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 4 — Acquisitions and Dispositions  – (continued)

In connection with 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 together with the Cash Election and the Stock Election, 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 30, 2014 deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares, 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 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 per share 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 Energy XXI common stock and paid approximately $1,012 million in cash.

The following table summarizes the total purchase price of approximately $1,504.3 million, including cash acquired of $206.1 million (in millions, except 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
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 that were held by EPL stockholders that did not make an election prior to the May 30, 2014 election deadline.

116

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 4 — Acquisitions and Dispositions  – (continued)

The following table summarizes the final 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 properties(a)
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	)		(2,058	)		(316,707	)
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 taxes(b)		(118,359	)		(340,645	)		(459,004	)
Other long-term liabilities		(2,242	)		797			(1,445	)
Total fair value, excluding goodwill		618,350			556,698			1,175,048
Goodwill(c)(d)		—			329,293			329,293
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% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit).

(c) See Note 5 — “Goodwill” for more information regarding goodwill impairment at December 31, 2014.

(d) On April 2, 2013, EPL sold certain shallow water GoM Shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million. This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million.

In accordance with the acquisition method of accounting, we have allocated the purchase price from our acquisition of EPL 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; 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 was recorded as goodwill. Goodwill recorded in connection with the EPL Acquisition is not deductible for income tax purposes.

117

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 4 — Acquisitions and Dispositions  – (continued)

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

The EPL Acquisition resulted in goodwill primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase our equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative expenditures by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, which enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets. During the quarter ended December 31, 2014, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 5 —  “Goodwill” for more information regarding the impairment of goodwill at December 31, 2014.

In the year ended June 30, 2014, costs associated with the EPL Acquisition totaled approximately $13.6 million and were expensed as incurred. For the years ended June 30, 2016 and 2015, our consolidated statement of operations includes EPL’s operating revenues of $255.8 million and $542.8 million, respectively, and net loss of $1,060.2 million and $1,298.7 million, respectively.

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 supplemental unaudited pro forma financial information is based on the historical consolidated statements of operations of Energy XXI and EPL for the year ended June 30, 2014 (in thousands, except per share amounts).

	Year Ended June 30, 2014
Revenues	$	1,783,062
Net loss		(45,233	)
Net loss available to Energy XXI common stockholders		(56,722	)
Net loss per share available to Energy XXI common stockholders:
Basic	$	(0.76	)
Diluted	$	(0.76	)

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 expense of $45.2 million of EPL’s exploration costs and impairment expense and $1.8 million of gain on sales of assets accounted for under the successful efforts method of accounting to correspond with EXXI’s full cost method of accounting.

118

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 4 — Acquisitions and Dispositions  – (continued)

b. Increase DD&A expense by $65.3 million for the EPL Properties to correspond with EXXI’s full cost method of accounting as well as the adjustments to fair value of the acquired assets.

c. Increase interest expense by $50.0 million to reflect interest on the $650 million 6.875% unsecured senior notes due 2024 and on additional borrowings under EXXI’s Revolving Credit Facility. Decrease interest expense $12.3 million to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million 8.25% senior notes due 2018 assumed in the EPL Acquisition.

We have accounted for our acquisitions using the acquisition method of accounting, and therefore, we have estimated the fair value of the assets acquired and liabilities assumed as of their respective acquisition dates. In the estimation of fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions, management used valuation techniques that convert future cash flows to single discounted amounts. Inputs to the valuation of oil and natural gas properties include estimates of: (i) oil and natural gas reserves; (ii) future operating and development costs; (iii) future oil and natural gas prices; and (iv) a discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (i) plugging and abandonment costs per well and related facilities; (ii) remaining life per well and facilities; (iii) an inflation factor; and (iv) a credit adjusted risk-free interest rate. Fair value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties which are beyond our control. These assumptions represent Level 3 inputs, as further discussed in Note 19 — “Fair Value of Financial Instruments”.

Sale of the Grand Isle Gathering System

On June 30, 2015, we sold certain real and personal property constituting a subsea pipeline gathering system located in the shallow GoM shelf and storage and onshore processing facilities on Grand Isle, Louisiana (the “GIGS”) to Grand Isle Corridor, LP (“Grand Isle Corridor”), a wholly-owned subsidiary of CorEnergy Infrastructure Trust, Inc. for cash consideration of $245 million, plus the assumption by Grand Isle Corridor of the asset retirement obligations associated with the estimated decommissioning costs for the GIGS. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss recognized. The net reduction to the full cost pool related to this sale was $248.9 million. Also on June 30, 2015, we entered into a triple-net lease agreement with Grand Isle Corridor pursuant to which we will continue to use and operate the GIGS as further discussed in Note 16 — “Commitments and Contingencies.”

Sale of interests in the East Bay field

On June 30, 2015, we sold our interest in the East Bay field to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC, for cash consideration of $21 million plus the assumption of asset retirement obligations estimated at $55.1 million. The cash consideration was payable in two installments with $5 million received at closing and the remainder in fiscal year 2016. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. Revenues and expenses related to the field were included in our results of operations through June 30, 2015. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss recognized. The net reduction to the full cost pool related to this sale was $68.9 million.

Subsequent to June 30, 2015, post closing adjustments reduced the total cash consideration to $20.3 million and the maximum receivable under the overriding royalty interest to $6.2 million.

119

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 5 — Goodwill

ASC 350, Intangibles — Goodwill and Other, requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment. Our annual goodwill impairment test is performed at least annually during the third quarter.

Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit.

At December 31, 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 necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. In light of the form of the acquisition of EPL (a purchase of stock), this goodwill had no tax basis when recognized, which resulted in no income tax benefit when impaired.

In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using an assumed weighted average cost of capital based on market participant data. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit were reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.

At June 30, 2016, included in other assets and debt issuance costs, net of accumulated amortization, on our consolidated balance sheets is $0.8 million of goodwill associated with the acquisition of a catering business on August 21, 2015.

120

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 6 — Property and Equipment

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

	June 30, 2016			June 30, 2015
Oil and gas properties
Proved properties	$	9,817,456		$	9,243,737
Less: accumulated depreciation, depletion, amortization and impairment		(9,256,513	)		(6,109,335	)
Proved properties, net		560,943			3,134,402
Unevaluated properties		42,212			436,357
Oil and gas properties, net		603,155			3,570,759
Other property and equipment		44,272			45,941
Less: accumulated depreciation		(26,662	)		(24,121	)
Other property and equipment, net		17,610			21,820
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	620,765		$	3,592,579

The following table summarizes an aging of total costs related to unevaluated properties excluded from the amortization base as of June 30, 2016 (in thousands).

	Net Costs Incurred During the Years Ended June 30,								Balance as of June 30, 2016
	2013 and prior		2014		2015		2016
Unevaluated Properties (acquisition costs)	$	617	$	23,662	$	—	$	17,933	$	42,212

At June 30, 2016, our investment in unevaluated properties primarily relates to the fair value of unproved oil and natural gas properties acquired in oil and natural gas property acquisitions (primarily the EPL Acquisition and M21K Acquisition). Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of (i) a determination as to whether there are any proved reserves related to the properties, (ii) a determination that the capital costs associated with the development of these properties will not be available, or (iii) ratably over a period of time of not more than four years. As of December 31, 2015, we had identified certain of our unevaluated properties totaling to $336.5 million as being uneconomical and transferred such amounts to the full cost pool, subject to amortization.

Due to the depressed commodity prices and our lack of capital resources to develop our properties, our proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result, we removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category on December 31, 2015 are still economic at current prices, but were reclassified to the contingent resource category because they were no longer expected to be drilled within five years of initial booking due to current constraints on our ability to fund development drilling.

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of

121

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 6 — Property and Equipment  – (continued)

our oil and natural gas properties to the amount of the discounted cash flows. For the years ended June 30, 2016 and 2015, our ceiling test computation resulted in impairments of our oil and natural gas properties totaling $2,813.6 million and $2,421.9 million, respectively. If the current low commodity price environment or downward trend in oil and natural gas prices continues, we will incur further impairment to our full cost pool in fiscal 2017 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

Note 7 — Equity Method Investments

Prior to the M21K Acquisition on August 11, 2015 discussed previously in Note 4 — “Acquisitions and Dispositions,” we owned a 20% interest in EXXI M21K which was engaged 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. EGC received a management fee from M21K for providing administrative assistance in carrying out its operations. We also provided a guarantee related to the payment of asset retirement obligations and other liabilities of M21K. EXXI M21K was a guarantor of a $100 million first lien credit facility agreement entered into by M21K, which had a $40 million borrowing base and under which $28.0 million in loans and $1.2 million in letters of credit were outstanding as of June 30, 2015. At June 30, 2015, M21K was in default due to a breach of certain covenants under this agreement. On August 11, 2015, we acquired all of the equity interests of M21K and repaid the outstanding balance under the M21K credit facility. See Note 14 — “Related Party Transactions.”

We recorded an equity loss of $10.7 million, $17.4 million and $4.3 million for the years ended June 30, 2016, 2015 and 2014, respectively. The equity loss for the year ended June 30, 2015 includes an other-than-temporary impairment related to our investment in EXXI M21K of $11.8 million.

Note 8 — Long-Term Debt

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

	June 30,
	2016		2015
Revolving Credit Facility	$	99,836	$	150,000
11.0% Senior Secured Second Lien Notes due 2020		1,450,000		1,450,000
8.25% Senior Notes due 2018		213,677		510,000
6.875% Senior Notes due 2024		143,993		650,000
3.0% Senior Convertible Notes due 2018		363,018		400,000
7.5% Senior Notes due 2021		238,071		500,000
7.75% Senior Notes due 2019		101,077		250,000
9.25% Senior Notes due 2017		249,452		750,000
4.14% Promissory Note due 2017		4,006		4,343
Debt premium, 8.25% Senior Notes due 2018(1)		—		29,459
Original issue discount, 11.0% Notes due 2020		—		(51,104	)
Original issue discount, 3.0% Senior Convertible Notes due 2018		—		(45,782	)
Derivative instruments premium financing		—		10,647
Capital lease obligations		714		869
Total debt		2,863,844		4,608,432
Less: current maturities		99,836		11,395
Less: liabilities subject to compromise (see Note 3)		2,764,008		—
Total long-term debt	$	—	$	4,597,037

(1) Represents unamortized premium on the 8.25% Senior Notes due 2018 assumed in the EPL Acquisition.

122

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 8 — Long-Term Debt  – (continued)

During the year ended June 30, 2016, we repurchased certain of our unsecured notes in aggregate principal amounts as follows: $506.0 million of 6.875% Senior Notes due 2024 (the “6.875% Senior Notes”), $261.9 million of 7.5% Senior Notes due 2021(the “7.5% Senior Notes”), $148.9 million of 7.75% Senior Notes due 2019(the “7.75% Senior Notes”), $296.3 million of 8.25% Senior Notes due 2018 (the “8.25% Senior Notes”) and $500.6 million of 9.25% Senior Notes due 2017 (the “9.25% Senior Notes”). We repurchased these notes in open market transactions at a total cost of approximately $215.9 million, (excluding accrued interest), and we recorded a gain on the repurchases totaling approximately $1,492.4 million, net of associated debt issuance costs and certain other expenses.

All of the repurchased notes, except for the 8.25% Senior Notes with face value of $266.6 million and 9.25% Senior Notes with face value of $471.1 million which both continue to be held by EGC, repurchased in February 2016, were cancelled. In addition, in March 2016 certain bondholders holding $37 million in face value of our 3.0% Senior Convertible Notes requested a conversion of their notes into common stock. Upon conversion, we recorded a gain of approximately $33.2 million after proportionate adjustment to the related debt issue costs, accrued interest and original debt issue discount.

As a result of the covenant violations that existed at March 31, 2016 that were not cured prior to the filing of the Bankruptcy Petitions, EGC’s pre-petition secured indebtedness under the Revolving Credit Facility and Second Lien Notes, Energy XXI Ltd’s pre-petition unsecured indebtedness under the 3.0% Senior Convertible Notes, EGC’s pre-petition unsecured indebtedness under the 6.875% Senior Notes, the 7.5% Senior Notes, the 7.75% Senior Notes and the 9.25% Senior Notes and EPL’s pre-petition unsecured indebtedness under the 8.25% Senior Notes became immediately due and payable and any efforts to enforce such payment obligations are automatically stayed as a result of the Chapter 11 Cases. Accordingly, all of our outstanding indebtedness was classified as current in the consolidated balance sheet and we accelerated the amortization of the associated debt premium and original issue discount, fully amortizing those amounts as of March 31, 2016. In addition, except for amounts related to the Revolving Credit Facility, we accelerated the amortization of the remaining debt issuance costs related to our outstanding indebtedness, fully amortizing those costs as of March 31, 2016. We currently believe that it is probable that we will enter into a potential restructuring agreement with the Lenders under our Revolving Credit Facility that will be approved by the Bankruptcy Court. Accordingly, we have not accelerated the amortization of remaining debt issue costs related to the Revolving Credit Facility. We continue to accrue interest on the Revolving Credit Facility subsequent to the Petition Date since we anticipate such interest will be allowed by the Bankruptcy Court to be paid to the Lenders. However, for all of our other indebtedness, in accordance with ASC 852, Reorganizations, we have accrued interest only up to the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $52.8 million, representing interest expense from the Petition Date through June 30, 2016.

The Debtors filing of the Bankruptcy Petitions on the Petition Date constituted an event of default under the indenture governing EGC’s secured indebtedness and EGC’s, EXXI’s and EPL’s unsecured indebtedness and accelerated the indebtedness thereunder. Pursuant to the Restructuring Support Agreement, as amended, holders of the Second Lien Notes Claims will receive their pro rata share of 87.8% of the New Equity in the reorganized company on account of such Second Lien Notes Claims, subject to dilution from the issuance of New Equity in connection with the Management Incentive Plan. However, even if our Plan meets other requirements under the Bankruptcy Code, creditors may not vote in favor of our Plan, and certain parties in interest may file objections to the Plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Further, even if no objections are filed and the requisite acceptances of our Plan are received from creditors entitled to vote on the Plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Plan. However, even if our Plan meets other requirements under the Bankruptcy Code, creditors may not vote in favor of our

123

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 8 — Long-Term Debt  – (continued)

Plan, and certain parties in interest may file objections to the Plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Further, even if no objections are filed and the requisite acceptances of our Plan are received from creditors entitled to vote on the Plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Plan.

Additional information regarding the Chapter 11 proceedings is included in Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources.”

Revolving Credit Facility

The Revolving Credit Facility was entered into by EGC in May 2011. During the year ended June 30, 2016, this facility was amended as follows: the Fourteenth Amendment and Waiver to the Revolving Credit Facility on March 14, 2016 (the “Fourteenth Amendment”) which extended the term of the Thirteenth Amendment (defined below) until April 15, 2016; the Thirteenth Amendment and Waiver to the Revolving Credit Facility on February 29, 2016 (the “Thirteenth Amendment”); the Twelfth Amendment to the First Lien Credit Agreement on November 30, 2015 (the “Twelfth Amendment”) and the Eleventh Amendment and Waiver to the First Lien Credit Agreement on July 31, 2015 (the “Eleventh Amendment”). The Revolving Credit Facility currently has a maximum facility amount and borrowing base of $327.2 million, of which such amount $99.4 million is the borrowing base under the sub-facility established for EPL. Borrowings under our First Lien Credit Agreement are limited to a borrowing base based on oil and natural gas reserve values, which are redetermined on a periodic basis. The scheduled date of maturity of the First Lien Credit Agreement is April 9, 2018.

The Revolving Credit Facility is secured by mortgages on at least 90% of the value of EGC and its subsidiaries’ (other than EPL and its subsidiaries until they shall have become guarantors of the EGC indebtedness under the First Lien Credit Agreement) proved reserves and proved developed producing reserves, but with the threshold for such properties of EPL and its subsidiaries (until they shall have become guarantors of the EGC indebtedness under the First Lien Credit Agreement) at 85%. Additionally, as a result of the Twelfth Amendment, EPL is required to maintain $30 million of restricted cash in an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement. Lender consent is required for any asset disposition that would have the effect of reducing the borrowing base by more than $5 million in the aggregate. The Eleventh Amendment waived certain provisions of the First Lien Credit Agreement to permit the M21K Acquisition as well as an additional minor acquisition and disposition.

The Company’s election to not make an interest payment on EPL’s 8.25% Senior Notes due on February 16, 2016 commenced a 30-day grace period, although such an election did not constitute an event of default under the indenture governing the 8.25% Senior Notes or any other debt instruments; however, under the Revolving Credit Facility agreement, the missed payment constituted a default under which no portion of the outstanding principal amount may be continued as a London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.75% to 3.75% rate loan. Accordingly, on February 25, 2016, all the outstanding principal amounts was subjected to an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. The applicable commitment fee under the facility is 0.50%. As a result of the filing of the Bankruptcy Petitions, the highest of the margins currently applies and default interest is accruing under the facility through an additional 2.00% PIK interest. PIK interest totaling $0.4 million was accrued from the Petition Date through June 30, 2016.

124

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 8 — Long-Term Debt  – (continued)

The Thirteenth and Fourteenth Amendments provided that the Company was not required to deliver a compliance certificate for the fiscal quarter ended December 31, 2015 until their respective expiration dates. The following additional changes to the First Lien Credit Agreement became effective upon the execution of the Thirteenth Amendment:

• Prohibiting EGC and EPL from borrowing under the First Lien Credit Agreement before March 15, 2016.

• Requiring EGC and EPL to deposit all cash and investments in accounts covered by control agreements in favor of the administrative agent.

• Allowing for EGC and EPL to get replacement letters of credit under the First Lien Credit Agreement without satisfying the credit extension conditions in the First Lien Credit Agreement so long as the replacement letter of credit does not have an aggregate face amount in excess of the available amount of the letter of credit being replaced and certain other conditions set forth in the Thirteenth Amendment are met.

The Fourteenth Amendment provided for the reduction of our borrowing base under the First Lien Credit Agreement. The borrowing base under the First Lien Credit Agreement as of the effectiveness of the Fourteenth Amendment was reduced from $500 million to $377.8 million, with such reduction effectively removing any further borrowing capacity under the First Lien Credit Agreement beyond an aggregate amount equal to the amount of outstanding letters of credit that have been issued thereunder plus the amount of outstanding loans to EPL thereunder. In connection with such reduction, the Fourteenth Amendment provided that we unwind certain hedging transactions and use the proceeds therefrom to repay amounts of outstanding loans to EPL under the First Lien Credit Agreement, and for such repayments to then result in an automatic and permanent reduction in our borrowing base. This further reduction in borrowing base was for both the overall borrowing base under the First Lien Credit Agreement as well as the borrowing base specific to EPL, and in each case, the reduction is an amount equal to the full extent of the aggregate amount of repaid principal relating to such unwound hedging transactions. Accordingly, on March 15, 2016, we unwound and monetized all of our outstanding crude oil and natural gas contracts and received $50.6 million and paid this amount to reduce EPL’s borrowing base.

The Fourteenth Amendment continued to allow us to get replacement letters of credit under the First Lien Credit Agreement without satisfying credit extension conditions so long as the replacement letter of credit did not have an aggregate face amount in excess of the available amount of the letter of credit being replaced and certain other conditions set forth in the Fourteenth Amendment were met.

In connection with the issuance of the Second Lien Notes as described below under “11.0% Senior Secured Second Lien Notes Due 2020” on March 3, 2015, EGC and EPL entered into the Tenth Amendment (the “Tenth Amendment”) to their second amended and restated First Lien Credit Agreement. Under the Tenth Amendment, the following changes, among others, to the First Lien Credit Agreement became effective:

• reduction of the maximum facility amount to $500 million and establishment of the borrowing base at such $500 million, of which such amount $150 million was the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement;

125

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 8 — Long-Term Debt  – (continued)

• addition of provisions to permit EGC to make a loan to EPL in the amount of $325 million using proceeds from the incurrence of additional permitted second lien or third lien indebtedness of EGC and for EPL and its subsidiaries to secure such loan by providing liens on substantially all of their assets that are second in priority to the liens of the Lenders under the First Lien Credit Agreement pursuant to the terms of an intercreditor agreement and restricting the transfer of EGC’s rights in respect of such loan or making any prepayment or otherwise making modifications of the terms of such arrangements; and

• elimination, addition, or modification of certain financial covenants.

As of June 30, 2016, we had $99.4 million in borrowings and $227.8 million in letters of credit issued under the First Lien Credit Agreement. As of June 30, 2015, we had $150.0 million in borrowings and $226.0 million in letters of credit issued under the Revolving Credit Facility. During the year ended June 30, 2015, as a result of the reduction in the borrowing capacity under the Revolving Credit Facility pursuant to the Tenth Amendment, we wrote off $8.9 million of previously capitalized debt issue costs.

11.0% Senior Secured Second Lien Notes Due 2020

On March 12, 2015, EGC issued $1,450 million in aggregate principal amount of 11.0% senior secured second lien notes due March 15, 2020 pursuant to the Purchase Agreement (the “Purchase Agreement”) by and among EGC, Energy XXI Ltd, Energy XXI USA, Inc. (“EXXI USA”) and certain of EGC’s wholly owned subsidiaries (together with Energy XXI Ltd and EXXI USA, the “Guarantors”), and Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC and Imperial Capital, LLC, as representatives of the initial purchasers named therein (the “Initial Purchasers”). EGC received net proceeds of approximately $1,355 million in the offering after deducting the Initial Purchasers’ discount and direct offering costs. The Second Lien Notes were sold to investors at a price of 96.313% of principal, for a yield to maturity at issuance of 12.0%. The Second Lien Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act. The Second Lien Notes and the related guarantees have not been, and will not be, registered under the Securities Act or the securities laws of any other jurisdiction. The Second Lien Notes bear interest from the date of their issuance at an annual rate of 11.0% with interest due semi-annually, in arrears, on March 15^th and September 15^th, beginning September 15, 2015. EGC incurred underwriting and direct offering costs of $41.7 million which were recorded as debt issuance costs.

The Second Lien Notes were issued pursuant to an indenture, dated March 12, 2015 (the “2015 Indenture”), among EGC, the Guarantors and U.S. Bank National Association, as trustee. The Second Lien Notes are secured by second-priority liens on substantially all of EGC and its subsidiary guarantors’ assets and all of EXXI USA’s equity interests in EGC, in each case to the extent such assets secure our Revolving Credit Facility. The liens securing the Second Lien Notes and the related guarantees are contractually subordinated to the liens on such assets securing our Revolving Credit Facility and any other priority lien debt, to the extent of the value of the collateral securing such obligations, pursuant to the terms of an intercreditor agreement, and to certain other secured indebtedness, to the extent of the value of the assets subject to the liens securing such indebtedness.

The Second Lien Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain of EGC’s future subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2015 Indenture. Although the Second Lien Notes are guaranteed by Energy XXI Ltd and EXXI USA, Energy XXI Ltd and EXXI USA will not, subject to certain exceptions, be subject to the restrictive covenants in the 2015 Indenture.

126

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 8 — Long-Term Debt  – (continued)

The 2015 Indenture restricts EGC’s ability and the ability of its restricted subsidiaries to: (i) transfer or sell assets; (ii) make loans or investments; (iii) pay dividends, redeem subordinated indebtedness or make other restricted payments; (iv) incur or guarantee additional indebtedness or issue disqualified capital stock; (v) create or incur certain liens; (vi) incur dividend or other payment restrictions affecting certain subsidiaries; (vii) consummate a merger, consolidation or sale of all or substantially all of EGC’s assets; (viii) enter into transactions with affiliates; and (ix) engage in business other than the oil and gas business. These covenants are subject to a number of important exceptions and qualifications.

8.25% Senior Notes Due 2018

On June 3, 2014, EGC assumed the 8.25% Senior Notes in the 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, governing EPL’s 8.25% Senior Notes. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL’s obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

6.875% Senior Notes Due 2024

On May 27, 2014, EGC issued at par $650 million in aggregate principal amount of the 6.875% Senior Notes due March 15, 2024. On June 1, 2015, we completed a registered offer to exchange the 6.875% Senior Notes for a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. EGC incurred underwriting and direct offering costs of approximately $11 million which were recorded as debt issuance costs.

The indenture governing the 6.875% Senior Notes, among other things, limits 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 natural gas business.

3.0% Senior Convertible Notes due 2018

On November 18, 2013, Energy XXI Ltd sold $400 million face value of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). We incurred underwriting and direct offering costs of $7.6 million which were recorded as debt issuance costs. 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 election of Energy XXI Ltd, 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

127

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 8 — Long-Term Debt  – (continued)

$40.40 per share of common stock). The conversion rate, and accordingly 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 3.0% 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 3.0% Senior Convertible Notes, which has been reflected as additional paid-in capital. Based on applying the implied straight debt rate, the $400 million aggregate principal amount of the 3.0% Senior Convertible Notes was recorded at $336.6 million and the original issue discount of $63.4 million was amortized as an increase in interest expense on the 3.0% Senior Convertible Notes.

As described in the indenture governing the 3.0% Senior Convertible Notes, the 3.0% Senior Convertible Notes can be converted in multiples of $1,000 principal amount, upon request by the bondholder, if prior to September 15, 2018, during the five consecutive business-day period following any ten consecutive trading-day period in which the trading price per $1,000 principal amount of 3.0% Senior Convertible Notes for each trading day during such ten trading-day period was less than 98% of the closing sale price of our common stock for each trading day during such ten trading-day period multiplied by the then current conversion rate. In March 2016, each $1,000 principal amount of 3.0% Senior Convertible Notes were trading substantially lower than 98% of the value of our common stock multiplied by the then current conversion rate. Accordingly, certain bondholders holding $37 million in face value of our 3.0% Senior Convertible Notes requested conversion into shares of our common stock. Upon conversion, we elected to issue shares of our common stock and delivered 915,385 shares of our common stock with fractional shares settled in cash. We followed the guidance in ASC 470-20, Debt with Conversion and Other Options, to record such conversion which allows for the allocation of fair value of the consideration transferred to the bondholder between the liability and equity components of the original instrument, recognition of gain or loss on debt extinguishment and allocation of remaining consideration transferred to reacquire the equity component. Accordingly, we recorded a debt extinguishment gain of approximately $33.2 million and proportionately adjusted the related debt issue costs, accrued interest and original debt issue discount.

7.5% Senior Notes Due 2021

On September 26, 2013, EGC issued at par $500 million aggregate principal amount of 7.5% unsecured senior notes due December 15, 2021 (the “7.5% Senior Notes”). In April 2014, we completed a registered 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. EGC incurred underwriting and direct offering costs of $8.6 million which were recorded as debt issuance costs.

The indenture governing the 7.5% Senior Notes limits, among other things, 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 sell all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and natural gas business.

7.75% Senior Notes

On February 25, 2011, EGC issued at par $250 million aggregate principal amount of 7.75% unsecured senior notes due June 15, 2019 (the “7.75% Old Senior Notes”). On July 7, 2011, EGC exchanged the 7.75% Old Senior Notes for newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) with identical terms and conditions. EGC incurred underwriting and direct offering costs of $3.1 million which were recorded as debt issuance costs.

128

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 8 — Long-Term Debt  – (continued)

9.25% Senior Notes

On December 17, 2010, EGC issued at par $750 million aggregate principal amount of 9.25% unsecured senior notes due December 15, 2017 (the “9.25% Old Senior Notes”). On July 8, 2011, EGC exchanged $749 million of the 9.25% Old Senior Notes for $749 million of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act with identical terms and conditions. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011. EGC incurred underwriting and direct offering costs of $15.4 million which were recorded as debt issuance costs.

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.

On April 14, 2016, the Debtors filed the Bankruptcy Petitions, which constituted an event of default under the promissory note and accelerated the indebtedness thereunder.

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions were with Lenders under the 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, 2016 and 2015, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $0 and $10.6 million, respectively.

Interest Expense

The filing of the Bankruptcy Petitions constituted an event of default with respect to our existing debt obligations. Accordingly the Company’s pre-petition secured indebtedness under the Revolving Credit Facility, Second Lien Notes and EPL and EGC unsecured notes became immediately due and payable and any efforts to enforce such payment obligations are automatically stayed as a result of the Chapter 11 Cases. In addition, as a result of the covenant violations that existed at March 31, 2016 that were not cured prior to the filing of the Bankruptcy Petitions, all of our outstanding indebtedness was classified as current in the consolidated balance sheet at March 31, 2016, and we accelerated the amortization of the associated debt premium and original issue discount, fully amortizing those amounts as of March 31, 2016. In addition, except for amounts related to the Revolving Credit Facility, we accelerated the amortization of the remaining debt issuance costs related to our outstanding indebtedness, fully amortizing those costs as of March 31, 2016. We currently believe that it is probable that we will enter into a potential restructuring agreement with the Lenders under our Revolving Credit Facility that will be approved by the Bankruptcy Court. Accordingly, we have not accelerated the amortization of remaining debt issue costs related to the Revolving Credit Facility. We continue to accrue interest on the Revolving Credit Facility subsequent to the Petition Date since we anticipate that such interest will be allowed by the Bankruptcy Court to be paid to the Lenders. However, for all our other indebtedness, in accordance with accounting guidance in ASC 852, Reorganizations, we have accrued interest only up to the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $52.8 million, representing interest expense from the Petition Date through June 30, 2016.

129

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 8 — Long-Term Debt  – (continued)

Interest expense consisted of the following (in thousands):

	Year Ended June 30,
	2016			2015			2014
Revolving Credit Facility	$	15,703		$	25,506		$	13,956
11.0% Second Lien Notes due 2020		125,852			48,505			—
8.25% Senior Notes due 2018		27,899			42,075			3,507
6.875% Senior Notes due 2024		18,033			44,701			4,096
3.0% Senior Convertible Notes due 2018		9,340			12,000			7,266
7.50% Senior Notes due 2021		17,414			37,500			28,542
7.75% Senior Notes due 2019		8,200			19,375			19,375
9.25% Senior Notes due 2017		44,944			69,375			69,375
4.14% Promissory Note due 2017		130			192			210
Amortization of debt issue cost – Revolving Credit Facility		5,185			12,491			3,076
Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020		6,249			2,358			—
Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 – accelerated		44,855			—			—
Amortization of debt issue cost – 11.0% Second Lien Notes due 2020		5,047			1,887			—
Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 – accelerated		36,243			—			—
Amortization of fair value premium – 8.25% Senior Notes due 2018		(8,818	)		(11,108	)		(841	)
Amortization of fair value premium – 8.25% Senior Notes due 2018 – accelerated		(7,961	)		—			—
Amortization of debt issue cost – 6.875% Senior Notes due 2024		457			1,127			102
Amortization of debt issue cost – 6.875% Senior Notes due 2024 – accelerated		1,946			—			—
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018		8,917			11,232			6,418
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 – accelerated		33,370			—			—
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018		1,142			1,439			801
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 – accelerated		4,271			—			—
Amortization of debt issue cost – 7.50% Senior Notes due 2021		478			1,051			783
Amortization of debt issue cost – 7.50% Senior Notes due 2021 – accelerated		2,822			—			—
Amortization of debt issue cost – 7.75% Senior Notes due 2019		168			388			388
Amortization of debt issue cost – 7.75% Senior Notes due 2019 – accelerated		491			—			—
Amortization of debt issue cost – 9.25% Senior Notes due 2017		1,902			2,358			2,206
Amortization of debt issue cost – 9.25% Senior Notes due 2017 – accelerated		913			—			—
Derivative instruments financing and other		466			856			987
Bridge commitment fee		—			—			2,481
	$	405,658		$	323,308		$	162,728

130

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 9 — Asset Retirement Obligations

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

	Year Ended June 30,
	2016			2015
Beginning of period total	$	487,085		$	559,834
Liabilities acquired		66,700			—
Liabilities incurred and true-up to liabilities settled		34,167			40,820
Liabilities settled		(78,273	)		(106,573	)
Liabilities sold		—			(65,752	)
Revisions*		(36,750	)		8,675
Accretion expense		64,690			50,081
End of period total		537,619			487,085
Less: End of period, current portion		71,717			33,286
End of period, noncurrent portion	$	465,902		$	453,799

* This downward revision was primarily due to declining service costs resulting from the decline in commodity prices and decrease in demand for oil field services due to excess capacity.

Note 10 — Derivative Financial Instruments

We have historically entered into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use various instruments including financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars in our hedging portfolio. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying consolidated balance sheets. Any gains or losses resulting from changes in fair value of our outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statement of operations.

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, BRENT IPE and/or Argus-LLS) plus the difference between the purchased put and the sold put strike price.

Most of our crude oil production is Heavy Louisiana Sweet. We include contracts indexed to NYMEX WTI, ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.

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

131

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 10 — Derivative Financial Instruments  – (continued)

On March 14, 2016, the Fourteenth Amendment became effective and required us to unwind certain hedging transactions and use the proceeds therefrom to repay amounts of outstanding loans to EPL under the First Lien Credit Agreement, and for such repayments to then result in an automatic and permanent reduction in our borrowing base. Accordingly, on March 15, 2016, we unwound and monetized all of our outstanding crude oil and natural gas contracts and $50.6 million was applied to reduce amounts outstanding under our Revolving Credit Facility.

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

	Asset Derivative Instruments									Liability Derivative Instruments
	June 30, 2016				June 30, 2015					June 30, 2016				June 30, 2015
	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value			Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Derivative financial instruments		Current	$	—		Current	$	51,024			Current	$	—		Current	$	31,456
		Non-Current		—		Non-Current		11,980			Non-Current		—		Non-Current		9,440
Total Gross Commodity Derivative Instruments subject to enforceable master netting agreement				—				63,004					—				40,896
Derivative financial instruments		Current		—		Current		(28,795	)		Current		—		Current		(28,795	)
		Non-Current		—		Non-Current		(8,082	)		Non-Current		—		Non-Current		(8,082	)
Total gross amounts offset in Balance Sheets				—				(36,877	)				—				(36,877	)
Net amounts presented in Balance Sheets		Current		—		Current		22,229			Current		—		Current		2,661
		Non-Current		—		Non-Current		3,898			Non-Current		—		Non-Current		1,358
			$	—			$	26,127				$	—			$	4,019

The following table presents information about the components of the gain (loss) on derivative instruments (in thousands).

Gain (loss) on derivative financial instruments	Year Ended June 30,
	2016			2015		2014
Cash Settlements, net of purchased put premium amortization	$	59,081		$	81,049	$	(17,312	)
Proceeds from monetizations		50,588			102,354		—
Change in fair value		(19,163	)		52,036		(69,656	)
Total gain (loss) on derivative financial instruments	$	90,506		$	235,439	$	(86,968	)

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, 2016, we had no outstanding derivative contracts and, accordingly, no deposits for collateral with our counterparties.

Note 11 — Stockholders’ Equity

Common Stock

Our common stock was traded on the NASDAQ under the symbol “EXXI” prior to the delisting of our common stock in connection with the commencement of the Chapter 11 proceedings. Our common stock resumed trading on the OTC Pink under the symbol “EXXIQ” on April 25, 2016. Our shareholders are

132

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 11 — Stockholders’ Equity  – (continued)

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.

Late in fiscal year 2015, our Board of Directors decided to suspend the declaration of quarterly dividends on our common stock for the foreseeable future. During fiscal year 2015, we paid to holders of our common stock cash dividends of $0.12 per share on September 12, 2014 and December 12, 2014 and $0.01 per share on March 13, 2015 and June 12, 2015. During fiscal year 2014, we paid to holders of our common stock quarterly cash dividends of $0.12 per share.

On April 14, 2016, we received a letter from The NASDAQ Listing Qualifications Staff stating that the Staff has determined that the Company’s securities will be delisted from NASDAQ. The decision was reached by the Staff under NASDAQ Listing Rules 5101, 5110(b) and IM-5101-1 as a result of our announcement that we filed the Bankruptcy Petitions, the associated public interest concerns raised by the Bankruptcy Petitions, concerns regarding the residual equity interest of the existing listed securities holders and concerns about our ability to sustain compliance with all requirements for continued listing on NASDAQ. On February 24, 2016, we received a deficiency notice from NASDAQ stating that, based on the closing bid price of our common stock for the last 30 consecutive business days, we no longer met the minimum $1.00 per share requirement under NASDAQ Listing Rule 5450(a)(1). Because we did not request an appeal, trading of our common stock was suspended at the opening of business on April 25, 2016, and a Form 25-NSE was filed with the SEC on May 19, 2016, which removed our securities from listing and registration on NASDAQ.

Our securities resumed trading on the OTC Markets Group Inc.’s OTC Pink under the symbol “EXXIQ” on April 25, 2016. The OTC Pink is a significantly more limited market than NASDAQ, and the quotation of our common stock on the OTC Pink may result in a less liquid market available for existing and potential shareholders to trade shares of our common stock. This could further depress the trading price of our common stock and could also have a long-term adverse effect on our ability to raise capital. There can be no assurance that any public market for our common stock will exist in the future or that we will be able to relist our common stock on a national securities exchange. In connection with the delisting of our common stock, there may also be other negative implications, including the potential loss of confidence in the Company by suppliers, customers and employees and the loss of institutional investor interest in our common stock.

As described in Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources,” pursuant to the Restructuring Support Agreement entered into on April 11, 2016, it is expected that an order of the Bermuda court will be sought to dissolve Energy XXI Ltd under the laws of Bermuda concurrently with the Company’s emergence from Chapter 11, and (assuming that there are no assets available for distribution to equity under the Bermuda laws governing the payment of stakeholders in a Bermuda dissolution), existing equity holders would not receive distribution in respect of their equity interests in that dissolution. Accordingly any trading in shares of our common stock during the pendency of the Chapter 11 proceedings is highly speculative.

Our Board adopted a NOL Shareholder Rights Agreement (the “Rights Plan”) designed to preserve substantial tax assets of our U.S. subsidiaries. The Rights Plan is intended to protect our tax benefits and to allow all of our existing shareholders to realize the long-term value of their investment in the Company. The Board adopted the Rights Plan after considering, among other matters, the estimated value of the tax benefits, the potential for diminution upon an ownership change, and the risk of an ownership change occurring. Our ability to use these tax benefits would be substantially limited if we were to experience an “ownership change” as defined under Section 382 of the IRC (“Section 382”). An ownership change would occur if shareholders that own (or are deemed to own) at least 5% or more of our outstanding common stock increased their cumulative ownership in the Company by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. The Rights Plan reduces the likelihood that changes in our investor base would limit the Company’s future use of its tax benefits, which would significantly impair

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ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 11 — Stockholders’ Equity  – (continued)

the value of the benefits to all shareholders. To implement the Rights Plan, the Board declared a non-taxable dividend of one preferred share purchase right (“Rights”) for each outstanding share of common stock of Energy XXI. The rights will be exercisable if a person or group acquires 4.9% or more of our common stock. The rights will also be exercisable if a person or group that already owns 4.9% or more of our common stock acquires additional shares (other than as a result of a dividend or a stock split). Our existing shareholders that beneficially own in excess of 4.9% of the common stock were “grandfathered in” at their current ownership level. If the rights become exercisable, all holders of rights, other than the person or group triggering the rights, will be entitled to purchase our common stock at a 50% discount. Rights held by the person or group triggering the rights will become void and will not be exercisable.

The Rights will trade with shares of our common stock and will expire on February 15, 2017 unless our shareholders ratify the Rights Plan prior to such date, in which case the term of the Rights Plan is extended to three years. The Board may terminate the Rights Plan or redeem the rights prior to the time the rights are triggered.

Since the primary purpose of the Rights is to deter existing shareholders or new investors from acquiring more than 4.9% of our outstanding common stock, we believe that it is unlikely that the Rights would get triggered or exercised. Accordingly, since the fair value of the Rights is mostly derived from the probability of the Rights being exercised, we determined the Rights fair value to be immaterial.

As of June 30, 2016, no ownership change as defined in Section 382 had occurred and no Rights had been exercised.

In March 2016, each $1,000 principal amount of 3.0% Senior Convertible Notes were trading substantially lower than 98% of the value of our common stock multiplied by the then current conversion rate. Accordingly, certain bondholders holding $37 million in face value of our 3.0% Senior Convertible Notes requested conversion into shares of our common stock. Upon conversion, we elected to issue shares of our common stock and delivered 915,385 shares of our common stock with fractional shares settled in cash. For more information see Note 8 — “Long-Term Debt,” under the caption 3.0% Senior Convertible Notes Due 2018.

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. We have suspended the repurchase program indefinitely to reduce our capital needs. We did not make any repurchases under our repurchase program during the fiscal years ended June 30, 2016 and 2015. 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. As of June 30, 2016, $83.2 million remains available for repurchases under the share repurchase program.

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. On June 3, 2014, we reissued the entire 7,329,100 shares of common stock in treasury as part of our common stock issued to EPL stockholders upon merger.

As discussed in Note 4 — “Acquisitions and Dispositions,” upon closing of the EPL Acquisition, we issued 23,320,955 shares of our common stock, including the treasury shares, as noted above, as part of the Merger Consideration.

134

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 11 — Stockholders’ Equity  – (continued)

As discussed in Note 8 — “Long-Term Debt,” in November 2013 we sold $400 million of 3.0% Senior Convertible Notes. The $63.4 million allocated to the equity portion of the 3.0% Senior Convertible Notes, less offering costs of $1.4 million, were recorded as an increase in additional paid in capital. In addition, concurrently with the offering of our 3.0% Senior Convertible Notes in November 2013, we repurchased 2,776,200 shares of our 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.

Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock may be paid in cash, shares of our common stock, or a combination thereof. If we elect to make payment in shares of common stock, such shares shall be valued for such purpose 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.

As described in Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources,” pursuant to the Restructuring Support Agreement entered into on April 11, 2016, it is expected that an order of the Bermuda court will be sought to dissolve Energy XXI Ltd under the laws of Bermuda concurrently with the Company’s emergence from the Chapter 11 proceedings, and assuming that there are no assets available for distribution to equity under the Bermuda laws governing the payment of stakeholders in a Bermuda dissolution, existing equity holders would not receive distribution in respect of their equity interests in that dissolution. Accordingly, as of the Petition Date, we are no longer accruing dividends on preferred stock. Preferred stock dividends that would have accrued from the Petition Date through June 30, 2016 totaled approximately $2.1 million. Energy XXI suspended the quarterly dividends on the 5.625% Preferred Stock and the 7.25% Preferred Stock for the six months ended June 30, 2016, and, as a result, no dividends for the fiscal third or fourth quarter were paid to the holders of either series of preferred stock.

In the event of a liquidation, winding-up or dissolution of the Company, the 5.625% Preferred Stock and the 7.25% Preferred Stock would receive a liquidation preference of $250 and $100 per share, respectively, plus any accumulated or accrued dividends to be paid out of the assets of the Company available for distribution before any payment is made to our common stockholders. If the assets of the Company are insufficient to pay the full amounts owed to the holders of the 5.625% Preferred Stock and the 7.25% Preferred Stock, no distributions will be made on account of any shares of stock ranking equally to the 5.625% Preferred Stock and the 7.25% Preferred Stock unless done so equally, ratably and in proportion to the amounts to which all equally ranked holders are entitled.

The 5.625% Preferred Stock is convertible into 9.8353 shares of our common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 5.625% Preferred Stock Certificate of Designation. At June 30, 2015, the conversion rate was 10.4765 common shares per preferred share. On or after December 15, 2013, we may cause the 5.625% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of our common

135

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 11 — Stockholders’ Equity  – (continued)

stock equals or exceeds 130% of the then-prevailing conversion price. 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.

The 7.25% Preferred Stock is convertible into 8.77192 shares of our common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 7.25% Preferred Stock Certificate of Designation. At June 30, 2015, the conversion rate was 9.3439 common shares per preferred share. On or after December 15, 2014, we may cause the 7.25% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of our common stock equals or exceeds 150% of the then-prevailing conversion price.

Conversion of Preferred Stock

During the year ended June 30, 2016, we cancelled and converted 150,787 shares of our 5.625% Preferred Stock into a total of 1,579,522 shares of common stock using a conversion rate of 10.4765 common shares per preferred share.

During the year ended June 30, 2015, we cancelled and converted a total of 5,000 shares of our 7.25% Preferred Stock into a total of 46,472 shares of common stock using a conversion rate of 9.2940 common shares per preferred share. During the year ended June 30, 2015, we also cancelled and converted one share of our 5.625% Preferred Stock into 11 shares of common stock using a conversion rate of 10.2409 common shares per preferred share.

During the year ended June 30, 2014, we cancelled 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.

Notice Procedures and Transfer Restrictions

On April 14, 2016, the Debtors filed a motion (the “NOL Motion”) in the Bankruptcy Court for the entry of an order pursuant to Sections 105(a), 362 and 541 of the Bankruptcy Code to enable us to avoid limitations on the use of our tax net operating loss carryforwards and certain other tax attributes by imposing certain notice procedures and transfer restrictions on the acquisition (including by conversion) or disposition of the Company’s equity securities, including common stock, 5.625% Preferred Stock or 7.25% Preferred Stock (the “Stock”). The Bankruptcy Court granted the NOL Motion on an interim basis on April 15, 2016 and a final basis on May 19, 2016. In general, the final order granting the NOL motion (the “Order”) applies to any person or entity that, directly or indirectly, has (or would have, as a result of a proposed transaction) beneficial ownership of at least 4.9% of our outstanding Stock, as determined in accordance with applicable rules under Section 382 of the IRC (“Tax Ownership”).

Under the Order, any person or entity who has or acquires Tax Ownership of at least 4.9% of our common stock, 5.625% Preferred Stock or 7.25% Preferred Stock (each a “Substantial Equity Holder”) is required to file with the Bankruptcy Court, and serve on the Company, a notice containing certain Tax Ownership information set forth in the NOL Motion. Additionally, prior to any proposed acquisition of Stock that would result in an increase in the amount of our Stock beneficially owned by a Substantial Equity Holder, or that would result in a person or entity becoming a Substantial Equity Holder, such person, entity or Substantial Equity Holder is required to file with the Bankruptcy Court, and serve on the Company, a notice of such person, entity or Substantial Equity Holder’s intent to purchase, acquire or otherwise obtain Tax Ownership of Stock. Prior to effecting any sale, exchange, or other disposition of our Stock that would result in a decrease in the amount of our Stock beneficially owned by a Substantial Equity Holder, such Substantial

136

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 11 — Stockholders’ Equity  – (continued)

Equity Holder is required to file with the Bankruptcy Court, and serve on the Company, a notice of such Substantial Equity Holder’s intent to sell, exchange or otherwise dispose of Tax Ownership of Stock.

If we file written approval of a proposed Stock transaction with the Bankruptcy Court within fifteen calendar days of receipt of notice of such proposed transaction, then the proposed transaction may proceed. Otherwise, the transaction generally may not be consummated unless approved by a final and non-appealable order of the Bankruptcy Court. The Order further provides that any transfer of Tax Ownership of Stock in violation of the procedures set forth in the NOL Motion, including but not limited to the notice requirements, shall be null and void ab initio, and the person or entity making such transfer or declaration shall be required to take such steps as the Bankruptcy Court determines are necessary in order to be consistent with such transfer or declaration being null and void ab initio.

Note 12 — Supplemental Cash Flow Information

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

	Year Ended June 30,
	2016		2015		2014
Cash paid for interest	$	229,569	$	243,238	$	139,575
Cash paid for income taxes		150		933		3,641

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

	Year Ended June 30,
	2016			2015			2014
Financing of insurance premiums	$	—		$	—		$	21,967
Derivative instruments premium financing		—			12,025			11,257
Changes in capital expenditures accrued in accounts payable		(37,151	)		(168,569	)		115,696
Inventory transferred to oil and natural gas properties		7,081			—			—
Changes in asset retirement obligations		(2,583	)		49,495			299,225
Monetization of derivative instruments applied to Revolving Credit Facility		50,588			—			—
Treasury stock reissued for the EPL Acquisition		—			—			154,717
Common stock issued for the EPL Acquisition		—			—			337,588

Note 13 — 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. We have also awarded performance units (“Performance Units”), including both time-based performance units (“Time-Based Performance Units”) and Total Shareholder Return (“TSR”) 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.

At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due to employees will be settled in either common shares or cash. Historically, we have settled all vesting Restricted Stock Units awards in cash and accordingly they are accounted for under the liability method. The July 2015

137

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 13 — Employee Benefit Plans  – (continued)

vesting of the July 2014, 2013, and 2012 Performance Unit awards were also settled in cash. Subsequent to the Petition Date, any vesting of Restricted Stock Units or the Performance Units is accrued but not payable. Settlement with respect to the July 2016 vesting of the July 2015, 2014 and 2013 equity awards cannot be made without approval of the Bankruptcy Court, which approval is not currently being sought. Consequently no payments were made with respect to Restricted Stock Units and Performance Units that vested in July 2016 although the value associated with the vesting of such awards became determined and fixed on July 21, 2016. The holders of those awards will have an unsecured claim against the Company for the amount of payment associated with the July 2016 vesting.

Fiscal 2016 Performance Unit Grants.  For the Performance Units granted in fiscal 2016, the Total Shareholder Return (“TSR Modifier”) is linked to the performance of our common stock, and the price of our common stock is calculated using the simple average of the closing prices of our common stock for the period of twenty business days ending on the last business day of June 2018 (“TSR Stock Price”). The number of units that cliff vest on June 30, 2018 will be the number of performance unit awards granted multiplied by TSR Modifier which ranges from 0% to 300% for the TSR Stock Price range of less than $3 to $12. Prior to vesting, the holder of the granted units is not entitled to any rights as a holder of our common stock and is prohibited from selling, transferring or alienating or hypothecating the granted units. Within 30 days of vesting, we will issue common stock or at our discretion the holder may be paid cash for the vested units. Upon a change in control of the Company, as defined in the Incentive Plan, which will include the consummation of our Plan, fiscal 2016 Performance Units will become immediately vested and payable with respect to our actual TSR Stock Price at the Effective Time. Consequently, the 2016 Performance Units will only have value to the extent our TSR Stock Price equals or exceeds $3. Fiscal 2016 Restricted Stock Units do not vest upon a change of control.

Fiscal 2015 Performance Unit Grants.  For the Performance Units granted in fiscal 2015, the Remuneration Committee of the Board of Directors changed the performance measure within the Incentive Plan from absolute TSR to relative TSR compared to a performance peer group. Under this plan, executives will receive no payout for TSR performance below the 25^th percentile, a 50% payout for TSR performance at the 25^th percentile, a 100% payout for TSR performance at the median, and 200% payout for performance at or above the 75^th percentile. Payouts under this plan are capped at a target if absolute TSR is negative. In addition, the Remuneration Committee decided to eliminate the use of a $5 notional unit and instead will denominate units based on the stock price on the grant date. The Remuneration Committee also decided to eliminate the make-up feature for the fiscal 2015 awards. The make-up feature provided for additional compensation at the end of the third performance period if the TSR Unit Number Modifier was higher at the end of the third performance period than it was at the two prior vesting dates. The awards for fiscal 2015 were granted 25% in the form of Time-Based Performance Unit awards and 75% in the form of TSR Performance-Based Unit awards. Upon a change in control of the Company, as defined in the Incentive Plan which will include the consummation of our Plan, outstanding fiscal 2015 time based Performance Units will vest and be payable and outstanding Performance Units subject to TSR performance conditions will vest at a deemed 200% payout.

Fiscal 2014 Performance Unit Grants.  For the Performance Units granted in fiscal 2014, the amount due the employee at the vesting date is equal to the grant date unit value of $5.00 times the percentage increase in the stock price over the performance period, multiplied by the number of units that vest. If the stock price declines over the performance period, the amount due the employee at the vesting date is equal to the grant date unit value of $5.00, multiplied by the number of units that vest. For the fiscal year 2014 grant, the initial stock price was $22.48. For the TSR Performance-Based Units, the executive will receive a cash payment equal to the grant date unit value of $5.00 multiplied by (a) the cumulative percentage increase in the price per share of our common stock from the date on which the TSR Performance-Based Units were

138

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 13 — Employee Benefit Plans  – (continued)

granted and (b) the TSR Unit Number Modifier. If the stock price declines over the performance period, the amount due the executive at the vesting date is equal to the grant date unit value of $5.00, multiplied by the TSR Unit Number Modifier. In addition, the employee may have the opportunity to earn additional compensation based on our TSR at the end of the third performance period for the 2014 grant. Such additional compensation will apply if the TSR Unit Number Modifier is higher at the end of the third performance period than it was at the two prior vesting dates. Of the total Performance Units awarded, 25% are Time-Based Performance Units and 75% are TSR Performance-Based Units.

The fair values of our stock based units are based on the period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model historically has been 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 the valuation of the TSR Performance-Based Units. Because the final tranche of the fiscal 2014 Performance Units fixed on July 21, 2016, a change in control of the Company after that date will have no impact on the awards.

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

	Year Ended June 30,
	2016			2015			2014
Restricted Stock Units	$	(4,499	)	$	8,631		$	12,798
Performance Units		1,916			(4,692	)		11,446
Total compensation expense recognized	$	(2,583	)	$	3,939		$	24,244

As of June 30, 2016, we had 5,902,529 unvested Restricted Stock Units, 331,146 Time-Based Performance Units and 2,151,546 TSR Performance Based Units.

As described in Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources,” pursuant to the Restructuring Support Agreement entered into on April 11, 2016, it is expected that the dissolution of Energy XXI Ltd will be completed under the laws of Bermuda following the confirmation of the Plan by the Bankruptcy Court, and, given that it is unlikely to have assets available for distribution, existing equity holders would receive no distributions in respect of that equity in that dissolution. As described in the Restructuring Support Agreement, it is expected that the Plan will include a new long-term Management Incentive Plan for the Company upon emergence from the Chapter 11 proceedings. Such Management Incentive Plan will reserve up to 5% of the total New Equity on a fully diluted basis and will be a comprehensive equity based award plan with equity based awards (including stock option and restricted stock units) to be issued on terms and conditions determined by the board of directors of the New Entity.

Non-Executive Director Compensation.  On November 7, 2011, the Remuneration Committee approved the director compensation program which provided for an annual stock award of $175,000 worth of shares. Since then, this equity retainer has been paid in our common stock in an amount equivalent to $175,000 using our closing stock price on the date of the Annual General Meeting, which represents the grant date fair value computed in accordance with ASC Topic 718. However, for the fiscal year 2016, the Compensation Committee reviewed our director compensation program and elected to reduce the annual stock award by 50% to $87,500. Our lead independent director waived his annual stock retainer for fiscal year 2016. In addition, beginning with fiscal year 2016, the lead independent director will no longer receive any additional cash, equity or other compensation for serving in such capacity. As a result, for fiscal year 2016, five directors each received 53,681 shares of common stock based on a $1.63 closing price on the date of the 2015 Annual General Meeting. The shares will vest on the date of the 2016 Annual General Meeting. See Note 14 — 

139

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 13 — Employee Benefit Plans  – (continued)

“Related Party Transactions” for information regarding Restricted Stock Units and consulting fees paid to one of our directors for his services as our Interim Chief Strategic Officer.

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 at the then current market price per share. During the years ended June 30, 2016, 2015 and 2014, we issued 194,333 shares, 180,323 shares, and 148,519 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 Company suspended the Employee Stock Purchase Plan in April 2016 and refunded any withheld employee contributions related to the January 1, 2016 to June 30, 2016 offering period. We used 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, 2016, there was no unrecognized compensation expense. 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,
	2016		2015		2014
Compensation expense	$	344	$	785	$	866
Shares issued		185,496		365,541		92,297

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 upon issuance. During the year ended June 30, 2015, 50,000 of these stock options were forfeited and 150,000 remain outstanding. As of June 30, 2016, there was no unrecognized compensation expense.

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,
	2016		2015			2014
Profit Sharing Plan	$	—	$	(768	)	$	4,833
401(k) Plan		2,852		3,192			3,395
Total contributions	$	2,852	$	2,424		$	8,228

140

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 14 — Related Party Transactions

Prior to the M21K Acquisition on August 11, 2015, we had a 20% interest in EXXI M21K and accounted for this investment using the equity method. We had provided a guarantee related to the payment of asset retirement obligations and other liabilities of M21K in the 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 of M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchase, we guaranteed payment of asset retirement obligations of M21K estimated at $18.6 million. For these guarantees, M21K 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 years ended June 30, 2016, 2015, and 2014, we received $0.3 million, $3.7 million and $3.1 million, respectively, related to such guarantees. Prior to the M21K Acquisition, we also received a management fee of $0.98 per BOE produced for providing administrative assistance in carrying out M21K operations. For the years ended June 30, 2016, 2015, and 2014, we received management fees of $0.2 million, $3.3 million and $3.8 million, respectively.

Effective January 15, 2015, our Board of Directors appointed one of its members, James LaChance, to serve as our interim Chief Strategic Officer. In that position, Mr. LaChance pursued discussions with our lenders and noteholders to improve our available capital, leverage ratios and average debt maturity, as directed by our Chief Executive Officer, in consultation with the Board. Mr. LaChance’s duties as interim Chief Strategic Officer were separate from, and in addition to, his responsibilities as a member of the Board of Directors. In light of the significant increase in the amount of time Mr. LaChance was required to spend performing in that new role, we and Mr. LaChance entered into an interim Chief Strategic Officer consulting agreement (the “Consulting Agreement”), with an effective date of January 15, 2015. Under the Consulting Agreement, Mr. LaChance was paid $200,000 per month for his services as interim Chief Strategic Officer. The consulting agreement expired on July 15, 2015. For years ended June 30, 2016 and 2015, Mr. LaChance earned and was paid consulting fees of $0.1 million and $1.1 million, respectively, under the Consulting Agreement.

In accordance with the Consulting Agreement, Mr. LaChance was also entitled to a success fee if he continuously provided consulting services through the closing of one or a series of transactions to provide us and our affiliates with additional capital of more than $1,000 million. The amount of this success fee was capped at $6 million, with up to $5 million payable upon achievement of objective criteria set forth in the Consulting Agreement and up to an additional $1 million payable in the Board of Directors’ discretion, based on qualitative factors. The success fee was earned and Mr. LaChance received, on March 12, 2015, 1,644,737 RSUs based on a price of $3.04 per share (the value weighted average price of our common stock for the period from December 1, 2014 through January 31, 2015), representing the full $5 million portion of the success fee.

With respect to the discretionary portion of the success fee, the Board of Directors awarded Mr. LaChance the full $1 million amount on October 15, 2015. Fifty percent of this amount was paid in cash in October 2015 and the other fifty percent was paid in the form of 231,482 RSUs, based on a price of $2.16 per share, which was the closing price of our common stock on October 15, 2015. All of the outstanding 1,876,219 RSUs were settled in cash for $1,182,018 on March 12, 2016 based on a price of $0.63 per share.

On October 9, 2015, the Board determined that the positions of Chief Executive Officer and Chairman of the Board should be held by two different individuals. As a result of that determination, the Board elected Mr. LaChance to serve as Chairman of the Board, effective as of October 15, 2015, to serve in such capacity until the earlier of his resignation or removal. Mr. LaChance will not receive any compensation for serving as Chairman of the Board, other than pursuant to director compensation programs that are applicable to other non-employee directors. Pursuant to the Restructuring Support Agreement entered into on April 11, 2016, the board of directors of the reorganized Debtors upon emergence from the Chapter 11 proceedings shall consist

141

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 14 — Related Party Transactions  – (continued)

of seven persons to be designated by the Majority Restructuring Support Parties, which will include John D. Schiller, Jr., the Company’s current President and Chief Executive Officer.

During the years ended June 30, 2015 and 2014, the Company’s Chief Executive Officer borrowed funds from personal acquaintances or their affiliates, certain of whom provide services to the Company (“Vendor Loans”). During the years ended June 30, 2016, 2015 and 2014, certain of those lenders provided services to the Company totaling $35.9 million, $34.7 million and $38.7 million, respectively. During 2014, one of our directors made a personal loan to the Chief Executive Officer at a time prior to becoming a director of the Company but while a managing director at Mount Kellett Capital Management LP, which at the time owned a majority interest in Energy XXI M21K and 6.3% of the Company’s common stock.

From time to time, we have entered into arrangements in the ordinary course of business with entities in which Cornelius Dupré II, who was appointed to our Board of Directors in October 2010, has an ownership interest. These entities provide us with oil field services, and during fiscal year ended June 30, 2016, 2015 and 2014 we made aggregate payments of approximately $5.6 million, $2.0 million and $0.6 million, respectively to these entities for those services.

Note 15 — Earnings (Loss) per Share

Basic earnings (loss) per share of common stock is computed by dividing net income (loss) attributable to 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, convertible notes, restricted stock and other potential common stock. The following table sets forth the calculation of basic and diluted earnings (loss) per share (“EPS”) (in thousands, except per share data):

	Year Ended June 30,
	2016			2015			2014
Net income (loss)	$	(1,918,751	)	$	(2,433,838	)	$	18,125
Preferred stock dividends		8,394			11,468			11,489
Net income (loss) attributable to common stockholders	$	(1,927,145	)	$	(2,445,306	)	$	6,636
Weighted average shares outstanding for basic EPS		95,822			94,167			74,375
Add dilutive securities		—			—			70
Weighted average shares outstanding for diluted EPS		95,822			94,167			74,445
Earnings (loss) per share
Basic	$	(20.11	)	$	(25.97	)	$	0.09
Diluted	$	(20.11	)	$	(25.97	)	$	0.09

For the years ended June 30, 2016, 2015 and 2014, 9,439,104, 8,642,434 and 8,336,700 shares of potential common stock, respectively, were excluded from the diluted average shares due to an anti-dilutive effect.

Note 16 — Commitments and Contingencies

Litigation.  We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. As described below, most of our pending legal proceedings have been stayed by virtue of filing the Bankruptcy Petitions on April 14, 2016. 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.

142

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 16 — Commitments and Contingencies  – (continued)

On June 17, 2016, the SEC filed a proof of claim against the Company asserting a general unsecured claim in the amount of $3.9 million based on alleged violations of the federal securities laws by Energy XXI pertaining to the failure to disclose the Vendor Loans and Mr. Schiller’s pledge of Energy XXI stock to a certain financial institution in the second half of 2014. If allowed, such claim against Energy XXI would be classified as a general unsecured claim under the Plan and would be subject to discharge, settlement, and release in connection with the Chapter 11 Cases, and receive the treatment provided to holders of general unsecured claims. The Debtors anticipate that they will object to the SEC’s claim.

Lease Commitments.  We have non-cancelable operating leases for office space and other assets that expire through December 31, 2022. In addition, on June 30, 2015, we entered into an operating lease agreement for the Grand Isle Gathering System as further described below. As of June 30, 2016, future minimum lease commitments under our operating leases are as follows (in thousands):

Year Ending June 30,
2017	$	37,933
2018		37,890
2019		38,065
2020		42,535
2021		52,336
Thereafter		232,197
Total	$	440,956

For the years ended June 30, 2016, 2015 and 2014, rent expense, including rent incurred on short-term leases but excluding GIGS, described below, was approximately $6.0 million, $6.4 million, and $3.7 million, respectively.

On June 30, 2015, in connection with the closing of the sale of the Grand Isle Gathering System, Energy XXI GIGS Services, LLC, an indirect wholly-owned subsidiary of the Company (the “Tenant”), entered into a triple-net lease (the “GIGS Lease”) with Grand Isle Corridor pursuant to which we will continue to operate the Grand Isle Gathering System. The primary term of the GIGS Lease is 11 years from the closing of the sale, with one renewal option, which will be the lesser of nine years or 75% of the expected remaining useful life of the Grand Isle Gathering System. The operating lease utilizes a minimum rent plus a variable rent structure, which is linked to the oil revenues we realize from the Grand Isle Gathering System above a predetermined oil revenue threshold. During the initial term, we will make fixed minimum monthly rental payments, which vary over the term of the lease. The aggregate annual minimum cash monthly payments for the first twelve months of the GIGS Lease total $31.5 million, and such payment amounts average $40.5 million per year over the life of the lease. Under the terms of the GIGS Lease, we retain any revenues generated from transporting third party volumes.

Under the terms of the GIGS Lease, we control the operation, maintenance, management and regulatory compliance associated with the Grand Isle Gathering System, and we are responsible for, among other matters, maintaining the system in good operating condition, paying all utilities, insuring the assets, repairing the system in the event of any casualty loss, paying property and similar taxes associated with the system, and ensuring compliance with all environmental and other regulatory laws, rules and regulations. The GIGS Lease also imposes certain obligations on Grand Isle Corridor, including confidentiality of information and keeping the Grand Isle Gathering System free of certain liens. In addition, we have, under certain circumstances, a right of first refusal during the term of the GIGS Lease and for two years thereafter to match any proposed transfer by Grand Isle Corridor of its interest as lessor under the GIGS Lease or its interest in the Grand Isle Gathering System.

143

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 16 — Commitments and Contingencies  – (continued)

Under the GIGS Lease, an event of default would be triggered by the Tenant upon (i) the filing by either the Tenant or the Company of a Bankruptcy Petition or (ii) the failure of either the Tenant or the Company to make any payment of principal or interest with respect to certain material debt of the Tenant or the Company, as a guarantor, after giving effect to any applicable cure period or the failure to perform under an agreement or instrument relating to such material debt (collectively, the “Specified Defaults”). Although the Tenant did not file a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code, the Company’s Bankruptcy Petition and failure to comply with its material debt instruments, would, among other things, allow Grand Isle Corridor to terminate the GIGS Lease.

As a result, the Tenant and Grand Isle Corridor entered into a Waiver to Lease, dated as of April 13, 2016 (the “Waiver”), whereby Grand Isle Corridor waived its right to exercise its remedies set forth under the GIGS Lease in the event of the Specified Defaults except its ability to exercise observer rights. The Waiver will terminate if any of the following events occur: (i) a dismissal of the Company’s Bankruptcy Petition, (ii) conversion of the pending case from a Chapter 11 bankruptcy to a chapter 7 bankruptcy case or other liquidation proceeding, (iii) relief from the automatic stay or other relief which allows the creditors of the material debt to take action to enforce such material debt against the Company or its property or (iv) a tenant event of default (as defined in the GIGS Lease) under the GIGS Lease other than arising out of the specified defaults expressly waived.

Letters of Credit and Performance Bonds.  As of June 30, 2016, we had $388.0 million of performance bonds outstanding and $225 million in letters of credit issued to a third party relating to assets in the Gulf of Mexico. We are a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (“OCS”) and our operations on these leases in the Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the BOEM. These leases compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws. Consequently, as of June 30, 2016, we have submitted approximately $226.6 million of our performance bonds in the form of general or supplemental bonds issued to the BOEM that may be accessed and used by the BOEM to assure our commitment to comply with our lease obligations, including decommissioning obligations. We also maintain approximately $161.4 million in performance bonds issued not to the BOEM but rather to predecessor third party assignors, including certain state regulatory bodies, of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities.

In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for exemption from certain supplemental bonding requirements for potential offshore decommissioning obligations and that certain of our subsidiaries must provide approximately $1,000 million in supplemental bonding or other financial assurance for our offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In October 2015, we received information from the BOEM that we could receive additional demands of supplemental bonding or other financial assurance for amounts in addition to the $1,000 million initially sought by the BOEM in April 2015, primarily relating to certain leases in which we have a legal interest that were no longer exempt from supplemental bonding as a result of co-lessees losing their exemptions. Since April 2015, we have had a series of discussions and exchanges of information with the BOEM regarding our submittal of additional supplemental bonding or other financial assurance with respect to offshore oil and gas interests that has resulted in, among other things: (i) our submittal of $150 million and $21.1 million in supplemental bonds to the BOEM in June 2015 and December 2015, respectively (which bond amounts are reflected in the $226.6 million in general and/or supplemental bonds discussed above); (ii) our selling of the East Bay field on June 30, 2015 that served to reduce by $178 million the $1,000 million of supplemental bonding or other financial assurance required by the BOEM in April 2015; and (iii) the BOEM’s agreement to, and execution of, a long-term financial assurance plan (the “Long-Term

144

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 16 — Commitments and Contingencies  – (continued)

Plan”) on February 25, 2016 that is intended to address the supplemental bonding and other financial assurance concerns expressed to us by the BOEM in April and October 2015.

Pursuant to the Restructuring Support Agreement entered into on April 11, 2016, it is anticipated that we will continue to perform our obligations under the Long-Term Plan during the pendency of the Chapter 11 Cases and in connection with the consummation of our restructuring. On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with the third party, it was agreed that subsequent to the Company’s emergence from the Chapter 11 proceedings, the letters of credit issued in favor the third party would be reduced to $200 million from the existing amount of $225 million. We submitted an amended and supplemental plan to the BOEM on June 28, 2016 and are currently awaiting their further response.

On July 14, 2016, the BOEM issued a new Notice to Lessees and Operators (“NTL”) regarding the need for additional security to satisfy decommissioning obligations and eliminating previous exemptions from the posting of financial assurances. Notwithstanding the BOEM’s July 14, 2016 NTL, the BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of compliance with our existing supplemental bonding requirements, including the obligations imposed upon us under the Long-Term Plan and the July 14, 2016 NTL, any other future BOEM directives, or any other changes to the BOEM’s rules applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, although we currently have $49.3 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors, we may be required to provide additional cash collateral in the future to support the issuance of such bonds or other financial security. While we are currently in compliance, we can provide no future assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient operating cash flows to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may have any of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties and one or more of such actions could have a material effect on our business, prospects, results of operations, financial condition, and liquidity.

Other.  We maintain restricted escrow funds as required by certain contractual arrangements. At June 30, 2016, our restricted cash included $30.1 million related to the First Lien Credit Agreement, $25.5 million in cash collateral associated with our bonding requirements, $1.7 million related to the GIGS transaction and approximately $6.0 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field which will be transferred to the buyer of our interests in that field.

We and our oil and gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments to our net costs or revenues and the related cash flows. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. We do not believe any such adjustments will be material.

Effect of Automatic Stay.  As disclosed in Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources,” the Debtors filed voluntary petitions for relief under the Bankruptcy Code on the Petition Date in the Bankruptcy Court. Each of the Debtors continues to operate its business and manage its property as a debtor-in-possession pursuant to Sections 1107 and 1108 of the Bankruptcy Code. Subject to certain exceptions under the Bankruptcy Code, the filing of the Debtors’ Chapter 11 Cases, pursuant to Section 362(a) of the Bankruptcy Code, automatically enjoined, or stayed, among other things, the continuation of most judicial or administrative proceedings or the filing of other actions against or on behalf of the Debtors or their

145

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 16 — Commitments and Contingencies  – (continued)

property to recover on, collect or secure a claim arising prior to the Petition Date or to exercise control over property of the Debtors’ bankruptcy estates, unless and until the Bankruptcy Court modifies or lifts the automatic stay as to any such claim. Notwithstanding the general application of the automatic stay described above, governmental authorities may determine to continue actions brought under regulatory powers. Thus, the automatic stay may have no effect on certain matters described above.

Note 17 — Income Taxes

We are a Bermuda company and are generally not subject to income tax in Bermuda. We have historically operated through our various subsidiaries in the United States, and, accordingly, U.S. income taxes have been provided based upon those U.S. operations and U.S. withholding tax on interest owed to our Bermuda parent on intercompany indebtedness. Pursuant to the Restructuring Support Agreement discussed in Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources,” we filed bankruptcy and dissolution petitions in the United States and Bermuda, respectively, on the Petition Date. These filings generally had no immediate effect on the Company’s income tax year or income tax reporting requirements, but will likely have future effects as discussed below.

Our Bermuda companies continue to record income tax expense reflecting 30% U.S. withholding tax on any interest (and interest equivalents) accrued on indebtedness of the U.S. companies held by them, and, consistent with this practice, we have accrued an additional withholding obligation of $8.2 million for the year ended June 30, 2016. This accrual policy changed effective with our bankruptcy filing on the Petition Date, in light of the Restructuring Support Agreement. During the year ended June 30, 2016, we have not made any cash withholding tax payments on management fees paid to our Bermuda entities, nor do we expect any such payments in the foreseeable future. We record the 30% withholding tax as a separate line item which is offset by other U.S. federal deferred tax assets in the consolidated financial statements to arrive at the zero net deferred tax asset/liability amounts presented. This accrued income tax liability related to withholding on interest expense due to our Bermuda parent is not a current liability due nor was listed as a pre-petition tax liability in our bankruptcy petition filed on the Petition Date. We paid $0.9 million cash in U.S. withholding taxes during the year ended June 30, 2015, 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 an accrued federal withholding obligation in the deferred tax liability section of the table below. In light of the valuation allowance, there is no net deferred tax asset or deferred tax liability presented on the consolidated balance sheets.

We have historically paid no significant U.S. cash income taxes (exclusive of withholding tax on Bermuda interest expense discussed above) due to the election to expense intangible drilling costs and the presence of our NOL carryforwards. Section 61(a)(12) of the IRC generally provides, in pertinent part, that income from the discharge of indebtedness (“CODI”) is treated as ordinary income subject to current taxation. The Company has completed several purchases of indebtedness during fiscal year 2016 at less than the issued amount of the indebtedness, which constitutes CODI. The U.S. Alternative Minimum Tax (“AMT”) only allows offset of 90% of AMT income by NOL carryforwards (with certain limited exceptions for 2009 and 2010 generated NOL’s), with the balance of income being taxed at 20%. IRC section 108(a)(1) provides that CODI may be excluded from taxable income of a debtor if the discharge occurred: (i) while the debtor was subject to a Title 11 (or similar) proceeding (such as a Chapter 11 filing), or (ii) while insolvent. The significance of exclusion treatment is that an NOL carryforward is not required to shield excluded CODI. If NOL’s were used to offset CODI (or other taxable income), the Company would be subject to a current cash AMT payment due to the 90% limitation in NOL usage against this tax. We believe, more likely than not, that prior to the bankruptcy filing, the Company was, for income tax purposes, insolvent as defined in IRC section 108(a)(1)(B) at the times of significant indebtedness repurchases and thus the exclusion applies to significant

146

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 17 — Income Taxes  – (continued)

indebtedness repurchases that constitute CODI. As such, we presently do not expect to make any cash AMT payments during this fiscal year. If any such AMT payments were required, we believe that, under present circumstances, we would not be able to record a net deferred tax asset for these payments, even though they result in a Minimum Tax Credit usable against future regular income tax with no expiration period. Thus, we believe that any current-year cash AMT payments would have a negative impact on earnings. We revise our ongoing estimated AMT obligation each quarter during the year and revise our expected income tax rate and cash tax payment disclosure accordingly.

In accordance with IRC Section 382 certain transfers of our equity, or issuances of equity in connection with our restructuring, may impair our ability to utilize our U.S. federal income tax NOL carryforwards and the tax basis of property (“Tax Attributes”) to offset future taxable income. A corporation is generally permitted to deduct from taxable income (or offset resulting income tax, in the case of credits) in any year NOL’s carried forward from prior years as well as certain DD&A cost recovery deductions relating to the recovery of its tax basis in properties post-discharge. We 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.

As described in detail in Note 11 — Stockholders’ Equity — Notice Procedures and Transfer Restrictions, the Bankruptcy Court has entered an interim order that places certain limitations on trading in our equity during the pendency of the Chapter 11 cases. Additional limitations pursuant to IRC section 382 can apply based upon the enterprise value of the Company upon exit, and many of these factors are based upon market elements and the results of negotiations that are forthcoming and are beyond the control of the Company. Despite these precautions, we can provide no assurances that these tax law limitations, market factors, or results of negotiations will prevent an “ownership change” or otherwise inhibit our ability to utilize our NOL’s or other Tax Attribute carryforwards as a result of our reorganization due to IRC section 382 ownership change limitations. Additionally, Tax Attribute reduction resulting from CODI exclusion is generally required irrespective of the application of IRC section 382 to changes in ownership of the Company. Accordingly, we expect that our Tax Attributes available for use after Company’s emergence from the Chapter 11 proceedings will be significantly limited.

Under Louisiana law, companies are required to file tax returns on a separate company basis; as such, EPL and EGC will not file a combined nor consolidated Louisiana income tax return. Our valuation allowance of $23.8 million at June 30, 2014 related to Energy XXI’s separate company Louisiana NOL carryforwards that we did not believe, on a more likely-than-not basis, would be realized in future years due to the focus on offshore operations. During fiscal year 2015, there were two changes in judgement affecting the amount of the valuation allowance. In the third quarter of fiscal year 2015, an intercompany transaction related to the sale of the GIGS generated current year Louisiana-only taxable income during fiscal year 2015 resulting in the release of $1.8 million of the previously recorded Louisiana valuation allowance. Subsequently, changes in our expectations regarding our future taxable income, consistent with net losses recorded during the current fiscal year (that are heavily influenced by oil and gas property impairments), caused us to record a net increase in our valuation allowance of $356.8 million resulting in a balance of $379.3 million at June 30, 2015. Due to continuing losses, we recorded an additional valuation allowance of $650 million resulting in a balance of $1,029.3 at June 30, 2016. We recorded this increase to our valuation allowance against our net deferred tax assets due to our judgment that our existing U.S. federal and State of Louisiana 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.

147

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 17 — Income Taxes  – (continued)

Our income (loss) before income taxes attributable to U.S. and non-U.S. operations are as follows (in thousands):

	Year Ended June 30,
	2016			2015			2014
U.S. income (loss)	$	(1,913,718	)	$	(3,050,659	)	$	43,915
Non-U.S. income (loss)		(5,120	)		3,471			9,230
Income (loss) before income taxes	$	(1,918,838	)	$	(3,047,188	)	$	53,145

The components of our income tax expense (benefit) are as follows (in thousands):

	Year Ended June 30,
	2016			2015			2014
Current
U.S.	$	—		$	933		$	3,641
Non U.S.		—			—			—
State		(87	)		99			—
Total current		(87	)		1,032			3,641
Deferred
U.S.		—			(564,569	)		31,379
State		—			(49,813	)		—
Total deferred		—			(614,382	)		31,379
Total income tax expense (benefit)	$	(87	)	$	(613,350	)	$	35,020

The following is a reconciliation of statutory income tax expense to our income tax provision (benefit) (in thousands):

	Year Ended June 30,
	2016			2015			2014
Income (loss) before income taxes	$	(1,918,838	)	$	(3,047,188	)	$	53,145
Statutory rate		35	%		35	%		35	%
Income tax expense (benefit) computed at statutory rate		(671,593	)		(1,066,516	)		18,601
Reconciling items
Federal withholding obligation		8,161			10,331			10,343
Nontaxable foreign income		1,791			91			(2,133	)
Change in valuation allowance		650,043			356,798			—
State income taxes (benefit), net of federal tax benefit		(87	)		(32,314	)		—
Non-deductible executive compensation		—			—			2,725
Non-deductible transaction costs		—			440			1,853
Tax basis in shortfall on partnership dissolution		6,501			—			—
Goodwill impairment		—			115,253			—
Other – Net		5,097			2,567			3,631
Income tax expense (benefit)	$	(87	)	$	(613,350	)	$	35,020

148

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 17 — Income Taxes  – (continued)

The most significant difference in our effective tax rate for the current year that differs from prior year’s activity (apart from changes in the valuation allowance) relates to the non-deductibility of certain bankruptcy restructuring related expenses.

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 (in thousands):

	June 30,
	2016			2015
Deferred tax assets – non current
Oil, natural gas properties and other property and equipment	$	646,294		$	—
Asset retirement obligation		190,923			170,480
Tax loss carryforwards on U.S. operations		99,612			458,530
Accrued interest expense		115,560			106,039
Deferred state taxes		54,793			54,973
Derivative instruments and other		—			4,879
Other		23,056			14,851
Total deferred tax assets – non current		1,130,238			809,752
Deferred tax liabilities
Oil, natural gas properties and other property and equipment		—			(272,502	)
Federal withholding obligation		(81,635	)		(73,474	)
Cancellation of debt		(9,680	)		(9,680	)
Employee benefit plans		(9,588	)		(9,588	)
Dismantlement		—			(9,086	)
Tax partnership activity		—			(56,130	)
Total deferred tax liabilities – non current		(100,903	)		(430,460	)
Valuation allowance		(1,029,335	)		(379,292	)
Net deferred tax asset (liability)	$	—		$	—

At June 30, 2016, we have a U.S. federal NOL carryforward of approximately $285 million, and state NOL carryforwards of approximately $800 million, including amounts carried into the Company’s U.S. group from the EPL acquisition. The regular U.S. federal income tax NOL’s will expire in various amounts beginning in 2026 and ending in 2035. The primary reason for the decrease in the NOL carryforward at June 30, 2016 is due to the required reduction in the tax attribute from excluding CODI from debt repurchases income while insolvent.

We have not recorded any reserves for uncertain tax positions. At June 30, 2016, 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 2015. The statute of limitations for examination of NOL’s 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 January 12, 2015, the U.S. Internal Revenue Service formally notified us that they had completed their examination of our U.S. federal income tax return for the year ended June 30, 2013, and that no changes were proposed to the tax reported (zero) or any tax attribute carried forward.

149

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 17 — Income Taxes  – (continued)

The pending bankruptcy restructuring will result in significant CODI which will not be currently subject to inclusion in taxable income of the Company, but will require the Company to reduce its NOL and other tax attribute carryforwards (including the tax basis in oil and natural gas properties that offset future taxable income through depletion, depreciation and amortization). As such, the Company does not expect to have any useable NOL carryforward after the restructuring, and its future tax DD&A will be severely limited. The amount of the future tax DD&A limitation will be largely based upon the results of the restructuring negotiations and assets values.

Note 18 — Concentrations of Credit Risk

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

Trafigura Trading LLC (“Trafigura”) accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2016. Chevron USA (“Chevron”) accounted for approximately 22% and 24% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015. Shell Trading Company (“Shell”) accounted for approximately 21%, 29%, and 45% of our total oil and natural gas revenues during the years ended June 30, 2016, 2015, and 2014, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 26%, and 43% of our total oil and natural gas revenues during the years ended June 30, 2015 and 2014, 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 Trafigura, Chevron or Shell 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 natural 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. At June 30, 2016, we had no derivative instruments outstanding.

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.

Geographic Concentration.  Virtually all of our current operations and proved reserves are concentrated in the Gulf of Mexico region. Therefore, we are exposed to operational, regulatory and other risks associated with the Gulf of Mexico, including the risk of adverse weather conditions. We maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed.

Note 19 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. 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

150

ENERGY XXI LTD
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 19 — Fair Value of Financial Instruments  – (continued)

(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 our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

For cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and certain notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. For the Second Lien Notes, 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, 6.875% Senior Notes and 3.0% Senior Convertible Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are Level 2 inputs within the fair value hierarchy. The carrying value of the Revolving Credit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

Our commodity derivative instruments historically consisted of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimated 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 10 — “Derivative Financial Instruments.”

The fair values of our stock based units are based on the period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model are 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 the valuation of the TSR Performance-Based Units.

151

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 19 — Fair Value of Financial Instruments  – (continued)

During the year ended June 30, 2016, 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, 2016		As of June 30, 2015		As of June 30, 2016		As of June 30, 2015
Assets:
Oil and natural gas derivatives	$	—	$	—	$	—	$	63,004
Liabilities:
Oil and natural gas derivatives	$	—	$	—	$	—	$	40,896
Restricted stock units		87		6,325		—		—
Time-based performance units		988		1,978		—		—
Total liabilities	$	1,075	$	8,303	$	—	$	40,896

The following table sets forth the carrying values and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments (in thousands):

	June 30, 2016				June 30, 2015
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Revolving credit facility	$	99,836	$	99,836	$	150,000	$	150,000
11% Senior Secured Second Lien Notes due 2020		1,450,000		587,250		1,398,896		1,276,000
8.25% Senior Notes due 2018		213,677		28,633		539,459		306,000
6.875% Senior Notes due 2024		143,993		16,559		650,000		211,250
3.0% Senior Convertible Notes due 2018		363,018		1,472		354,218		94,000
7.5% Senior Notes due 2021		238,071		25,807		500,000		164,925
7.75% Senior Notes due 2019		101,077		9,875		250,000		92,135
9.25% Senior Notes due 2017		249,452		25,943		750,000		413,160
	$	2,859,124	$	795,375	$	4,592,573	$	2,707,470

The Second Lien Notes, the 8.25% Senior Notes, the 6.875% Senior Notes, and the 7.5% Senior Notes each contain an option to redeem up to 35% of the aggregate principal amount of the respective notes outstanding with the net cash proceeds of certain equity offerings. Such options are considered embedded derivatives and are classified as Level 3 financial instruments for which the estimated fair values at June 30, 2016 and 2015 are not material.

The following table sets forth our Level 3 financial instruments (in thousands):

	Level 3
	Year Ended June 30,
	2016			2015
Liabilities:
Performance-based performance units
Balance at beginning of period	$	33		$	6,910
Vested		(775	)		—
Grants charged to general and administrative expense		760			(6,877	)
Balance at end of period	$	18		$	33

152

ENERGY XXI LTD
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 20 — Prepayments and Accrued Liabilities

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

	June 30,
	2016		2015
Prepaid expenses and other current assets
Advances to joint interest partners	$	974	$	1,294
Insurance		13,726		3,427
Inventory		423		7,867
Royalty deposit		2,168		3,137
Debt issuance costs		2,571		—
Other		9,166		8,573
Total prepaid expenses and other current assets	$	29,028	$	24,298
Accrued liabilities
Advances from joint interest partners		—		3,060
Employee benefits and payroll		7,377		18,927
Interest payable		—		83,384
Accrued hedge payable		—		1,399
Undistributed oil and gas proceeds		12,611		19,776
Severance taxes payable		619		843
Other		19,821		27,917
Total accrued liabilities	$	40,428	$	155,306

Note 21 — Selected Quarterly Financial Data — Unaudited

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

	Quarter Ended
	June 30,(2) 2016			March 31,(3) 2016			December 31,(4) 2015			September 30,(5) 2015
Revenues	$	147,804		$	116,285		$	184,615		$	257,823
Operating loss		(168,211	)		(417,866	)		(1,513,148	)		(918,200	)
Net income (loss)	$	(195,552	)	$	160,776		$	(1,310,583	)	$	(573,392	)
Preferred stock dividends		352			2,378			2,810			2,854
Net income (loss) attributable to common stockholders	$	(195,904	)	$	158,398		$	(1,313,393	)	$	(576,246	)
Net income (loss) per share attributable to common stockholders(1)
Basic	$	(2.01	)	$	1.65		$	(13.81	)	$	(6.08	)
Diluted		(2.01	)		1.55			(13.81	)		(6.08	)

(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.

(2) Included in Operating income (loss) is impairment of oil and natural gas properties of $134.9 million.

(3) Included in Operating income (loss) is impairment of oil and natural gas properties of $340.5 million and also included in Net income (loss) is gain on early extinguishment of debt of $777.0 million.

153

ENERGY XXI LTD
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

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

(4) Included in Operating income (loss) is impairment of oil and natural gas properties of $1,425.8 million and also included in Net income (loss) is gain on early extinguishment of debt of $290.3 million.

(5) Included in Operating income (loss) is impairment of oil and natural gas properties of $904.7 million and also included in Net income (loss) is gain on early extinguishment of debt of $458.3 million.

	Quarter Ended
	June 30,(2) 2015			March 31,(3) 2015			December 31,(4) 2014			September 30, 2014
Revenues	$	219,460		$	221,580		$	502,971		$	461,441
Operating income (loss)		(1,952,080	)		(698,583	)		(168,420	)		108,192
Net income (loss)	$	(1,690,004	)	$	(495,061	)	$	(275,963	)	$	27,190
Preferred stock dividends		2,864			2,862			2,870			2,872
Net income (loss) attributable to common stockholders	$	(1,692,868	)	$	(497,923	)	$	(278,833	)	$	24,318
Net income (loss) per share attributable to common stockholders(1)
Basic	$	(17.92	)	$	(5.27	)	$	(2.97	)	$	0.26
Diluted		(17.92	)		(5.27	)		(2.97	)		0.24

(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.

(2) Included in Operating income (loss) is impairment of oil and natural gas properties of $1,852.3 million.

(3) Included in Operating income (loss) is impairment of oil and natural gas properties of $569.6 million.

(4) Included in Operating income (loss) is goodwill impairment of $329.3 million.

Note 22 — Supplementary Oil and Gas Information — Unaudited

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 (in thousands):

	Year Ended June 30,
	2016		2015		2014
Property acquisitions
Proved	$	26,400	$	—	$	2,046,879
Unevaluated		—		2,304		924,882
Exploration costs		1,400		38,183		153,136
Development costs		57,400		608,605		632,262

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 associated with unevaluated properties are transferred to evaluated properties upon the earlier of (i) a determination as to whether there are any proved reserves related to the properties, or (ii) ratably over a period of time of not more than four years. As of December 31, 2015, we had identified certain of our unevaluated properties totaling to $336.5 million as being uneconomical and transferred such amounts to the

154

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

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

full cost pool, subject to amortization. We had no exploratory wells in progress at June 30, 2016. At June 30, 2016, we excluded from the amortization base the following costs related to unevaluated property costs (in thousands):

	Net Costs Incurred During the Years Ended June 30,								Balance as of June 30, 2016
	2013 and prior		2014		2015		2016
Unevaluated Properties (acquisition costs)	$	617	$	23,662	$	—	$	17,933	$	42,212

Estimated Net Quantities of Oil and Natural Gas Reserves

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

Estimated quantities of proved domestic oil and 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, 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
Production		(15,259	)		(37,472	)		(21,504	)
Extensions and discoveries		10,573			40,330			17,295
Revisions of previous estimates		(33,730	)		(75,617	)		(46,333	)
Purchases of reserves		(9,901	)		(13,554	)		(12,160	)
Proved reserves at June 30, 2015		137,072			278,543			183,496
Production		(13,547	)		(33,973	)		(19,209	)
Extensions and discoveries		1,416			1,729			1,704
Revisions of previous estimates		(64,584	)		(158,681	)		(91,031	)
Purchases of reserves		6,016			33,529			11,604
Proved reserves at June 30, 2016		66,373			121,147			86,564

155

ENERGY XXI LTD
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

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

	Oil (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed reserves
June 30, 2013		80,223		175,623		109,493
June 30, 2014		112,789		222,916		149,942
June 30, 2015		94,013		187,993		125,345
June 30, 2016		66,373		121,147		86,564
Proved undeveloped reserves
June 30, 2013		53,424		93,498		69,007
June 30, 2014		72,600		141,940		96,256
June 30, 2015		43,059		90,550		58,151
June 30, 2016		—		—		—

Our proved reserves decreased by 96.9 MMBOE or by approximately 53% from 183.5 MMBOE at June 30, 2015 to 86.6 MMBOE at June 30, 2016. The decrease was primarily due to:

• Downward revision of 54.3 MMBOE related to reclassification of proved undeveloped reserves to the contingent resource category. Due to the depressed commodity prices and our lack of capital resources to develop our properties, our proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result, we removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category on December 31, 2015 are still economic at current prices, but were reclassified to the contingent resource category because they were no longer expected to be drilled within five years of initial booking due to current constraints on our ability to fund development drilling. Due to continued constraints on available capital, our proved reserve estimates do not include any proved undeveloped reserves as of June 30, 2016. Further, the reclassification of proved undeveloped reserves also had an impact on the proved developed reserves volumes as it shortened the economic life of fields and thereby reduced economic production from the proved developed reserves category

• Production of 19.1 MMBOE during the year

• Downward revision of 28.7 MMBOE resulting from reduced oil and gas prices and shortened economic field life, and

• Downward revision of 8.1 MMBOE resulting from technical revisions

These were offset by:

• Reserve additions of 1.7 MMBOE, and

• Addition of 11.6 MMBOE due to acquisition of the remaining equity interests of M21K

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows as of June 30, 2016 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $39.63 per barrel of oil (calculated using the unweighted average first-day-of-the-month West Texas Intermediate posted prices during the 12-month period ending on June 30, 2016). 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 $42.69 per barrel of oil and $18.38 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. The $42.69 per barrel realized oil

156

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

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

price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $39.63 per barrel (differential of $3.06 per barrel).

For natural gas, the average Henry Hub price used was $2.24 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 $1.94 per Mcf after adjusting for energy content, transportation fees, and regional price differentials.

The standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves follows (in thousands):

	June 30,
	2016			2015		2014
Future cash inflows	$	2,966,317		$	10,641,151	$	20,162,506
Less related future
Production costs		2,223,645			4,131,526		5,500,669
Development and abandonment costs		1,033,717			1,970,526		2,959,994
Income taxes					168,655		2,546,155
Future net cash flows		(291,045	)		4,370,444		9,155,688
Ten percent annual discount for estimated timing of cash flows		(349,398	)		1,613,034		3,208,163
Standardized measure of discounted future net cash flows	$	58,353		$	2,757,410	$	5,947,525

Decrease in our proved reserves had a significant impact on our estimated standardized measure values of the proved reserves which declined from approximately $2,757 million as of June 30, 2015 to approximately $58 million as of June 30, 2016, mainly due to the following:

• Reduction in average adjusted prices used in determining revenues from $73.79 per barrel of oil and $3.08 per MMBtu of natural gas at June 30, 2015 to $42.69 per barrel of oil and $1.94 per MMBtu of natural gas at June 30, 2016. The average prices are calculated using the average of the first-day-of-the-month commodity prices during the 12 month period in the fiscal year

• Reclassification of proved undeveloped reserves to contingent resource category, and

• The reduction in proved developed reserves value resulting from shorter economic field life due to the reclassification of proved undeveloped reserves to contingent resources which caused both a reduction in proved developed reserves volumes and significant acceleration of abandonment costs for all fields

These were offset in part by reduction in lease operating expenses, capital expenditures and undiscounted abandonment costs due to current market conditions.

In connection with our restructuring as a result of the Chapter 11 proceedings, our ability to utilize our U.S. federal income tax NOL carryforwards and the tax basis of our property are expected to be materially impacted which will have an impact on our standardized measure of discounted future net cash flows.

157

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

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

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,
	2016			2015			2014
Beginning of year	$	2,757,410		$	5,947,525		$	4,481,522
Revisions of previous estimates
Changes in prices and costs		(3,287,459	)		(2,959,883	)		(196,159	)
Changes in quantities		(214,631	)		(2,390,099	)		(389,570	)
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		26,911			201,234			533,133
Purchases (sales) of reserves in place		212,961			(244,507	)		1,735,957
Accretion of discount		215,297			760,175			614,964
Sales, net of production and gathering and transportation costs		(212,581	)		(676,949	)		(836,019	)
Net change in income taxes		77,025			1,576,954			14,134
Changes in rate of production and other		4,189			(191,668	)		(253,290	)
Development costs incurred		10,493			237,173			247,865
Changes in estimated future development and abandonment costs		468,738			497,455			(5,012	)
Net change		(2,699,057	)		(3,190,115	)		1,466,003
End of year	$	58,353		$	2,757,410		$	5,947,525

Note 23 — Supplemental Guarantor Information

Our indirect, 100% wholly owned subsidiary, EGC, issued the 6.875% Senior Notes, the 7.5% Senior Notes, the 9.25% Senior Notes due 2017 and the 7.75% Senior Notes, each of which were replaced with identical notes issued in registered offerings. These notes are jointly, severally, fully and unconditionally guaranteed by the Bermuda parent company and each of EGC’s existing and future material domestic subsidiaries other than EPL and its subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the senior note indentures. These customary circumstances include: when a guarantor is declared “unrestricted” for covenant purposes, when the requirements for legal defeasance or covenant defeasance or to discharge the indenture have been satisfied, when the guarantor is sold or sells all of its assets or the guarantor no longer guarantees any obligations under EGC’s Revolving Credit Facility. When securities that are guaranteed are issued in a registered offering, Rule 3-10 of Regulation S-X of the SEC generally requires the issuer and guarantors to file separate financial statements. We meet the conditions in Rule 3-10 to instead report information about the assets, liabilities, results of operations and comprehensive income (loss) and cash flows of the parent, subsidiary issuer and subsidiary guarantors using an alternative approach, which is to include in a footnote to our financial statements, condensed consolidating financial information for the same periods as those presented in our financial statements.

158

ENERGY XXI LTD
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 23 — Supplemental Guarantor Information  – (continued)

The information is presented using the equity method of accounting for investments in subsidiaries. Transactions between entities are presented on a gross basis in the Bermuda parent company, EGC, guarantor subsidiaries, and non-guarantor subsidiaries columns with consolidating entries presented in the eliminations column. The principal consolidating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses.

159

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 23 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONDENSED CONSOLIDATING BALANCE SHEET

	June 30, 2016
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
	(In Thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	20,830		$	175,168		$	7,500		$	—		$	(240	)	$	203,258
Accounts receivable
Oil and natural gas sales		—			—			40,224			24,970			(1,550	)		63,644
Joint interest billings		—			2,912			1,263			4,595			—			8,770
Other		—			756			1,681			4,611			(1,829	)		5,219
Prepaid expenses and other current assets		314			19,143			1,306			8,265			—			29,028
Restricted cash					550			350			38,065			—			38,965
Total Current Assets		21,144			198,529			52,324			80,506			(3,619	)		348,884
Property and Equipment
Oil and natural gas properties, net		—			—			267,299			335,487			369			603,155
Other property and equipment, net		—			—			1,508			16,102			—			17,610
Total Property and Equipment, net		—			—			268,807			351,589			369			620,765
Other Assets
Equity investments		—			—			—			1,629,890			(1,629,890	)		—
Intercompany receivables		179,362			2,210,801			65,396			945,587			(3,401,146	)		—
Restricted cash		—			25,548			—			—			—			25,548
Other assets and debt issuance costs, net		172,697			347,173			2,832			6,412			(498,877	)		30,237
Total Other Assets		352,059			2,583,522			68,228			2,581,889			(5,529,913	)		55,785
Total Assets	$	373,203		$	2,782,051		$	389,359		$	3,013,984		$	(5,533,163	)	$	1,025,434
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current Liabilities
Accounts payable	$	—		$	7,961		$	23,030		$	16,311		$	(3,118	)	$	44,184
Accrued liabilities		12			748			8,463			31,699			(494	)		40,428
Asset retirement obligations		—			—			25,367			46,350			—			71,717
Current maturities of long-term debt		—			—			—			99,836			—			99,836
Total Current Liabilities		12			8,709			56,860			194,196			(3,612	)		256,165
Long-term debt, less current maturities		—			—			—			245,000			(245,000	)		—
Intercompany notes payable		—			—			—			26,859			(26,859	)		—
Deferred income taxes		28,121			—			—			—			(28,121	)		—
Asset retirement obligations		—			50			295,872			177,855			(7,875	)		465,902
Accumulated losses in excess of equity investments		2,585,839			2,371,106			—			—			(4,956,945	)		—
Other liabilities		—			5,258			6,893			9,153			—			21,304
Total Liabilities Not Subject to Compromise		2,613,972			2,385,123			359,625			653,063			(5,268,412	)		743,371
Liabilities subject to compromise		413,316			2,692,867			1,839,124			2,129,975			(4,139,134	)		2,936,148
Total Liabilities		3,027,288			5,077,990			2,198,749			2,783,038			(9,407,546	)		3,679,519
Stockholders’ Equity (Deficit)
Preferred stock
7.25% Convertible perpetual preferred stock		—			—			—			—			—			—
5.625% Convertible perpetual preferred stock		1			—			—			—			—			1
Common stock		488			1						12			(13	)		488
Additional paid-in capital		1,845,684			2,252,447			114,825			7,378,089			(9,745,361	)		1,845,684
Accumulated earnings (deficit)		(4,500,258	)		(4,548,387	)		(1,924,215	)		(7,147,155	)		13,619,757			(4,500,258	)
Total Stockholders’ Equity (Deficit)		(2,654,085	)		(2,295,939	)		(1,809,390	)		230,946			3,874,383			(2,654,085	)
Total Liabilities and Stockholders’ Equity (Deficit)	$	373,203		$	2,782,051		$	389,359		$	3,013,984		$	(5,533,163	)	$	1,025,434

160

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 23 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
(Debtor-in-Possession)

CONDENSED CONSOLIDATING BALANCE SHEET

	June 30, 2015
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
	(In Thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	37,053		$	719,609		$	—	$	186		$	—		$	756,848
Accounts receivable
Oil and natural gas sales		—			—			68,514		36,963			(5,234	)		100,243
Joint interest billings		—			2,015			—		10,418			—			12,433
Other		622			17,819			140		24,932			—			43,513
Prepaid expenses and other current assets		280			13,211			—		11,469			(662	)		24,298
Restricted cash		—			—			—		9,359			—			9,359
Derivative financial instruments		—			21,341			—		888			—			22,229
Total Current Assets		37,955			773,995			68,654		94,215			(5,896	)		968,923
Property and Equipment
Oil and natural gas properties, net		—			—			2,112,635		1,408,585			49,539			3,570,759
Other property and equipment, net		—			—			—		21,820			—			21,820
Total Property and Equipment, net		—			—			2,112,635		1,430,405			49,539			3,592,579
Other Assets
Derivative financial instruments		—			3,898			—		—			—			3,898
Equity investments		—			428,368			—		3,591,757			(4,009,290	)		10,835
Intercompany receivables		122,039			1,626,679			—		93,844			(1,842,562	)		—
Restricted cash		—			31,000			—		1,667			—			32,667
Other assets and debt issuance costs, net		176,861			464,617			—		8,729			(568,280	)		81,927
Total Other Assets		298,900			2,554,562			—		3,695,997			(6,420,132	)		129,327
Total Assets	$	336,855		$	3,328,557		$	2,181,289	$	5,220,617		$	(6,376,489	)	$	4,690,829
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current Liabilities
Accounts payable	$	—		$	39,378		$	41,027	$	81,052		$	(5,118	)	$	156,339
Accrued liabilities		976			69,566			16,060		166,851			(98,147	)		155,306
Deferred income taxes		24,174			—			—		—			(24,174	)		—
Asset retirement obligations		—			—			624		32,662			—			33,286
Derivative financial instruments		—			1,603			—		1,058			—			2,661
Current maturities of long-term debt		—			7,283			—		4,112			—			11,395
Total Current Liabilities		25,150			117,830			57,711		285,735			(127,439	)		358,987
Long-term debt, less current maturities		354,218			3,548,896			—		938,923			(245,000	)		4,597,037
Intercompany notes payable		—			—			—		565,105			(565,105	)		—
Deferred income taxes		—			—			—		—			—			—
Asset retirement obligations		—			50			251,444		209,431			(7,126	)		453,799
Derivative financial instruments		—			1,358			—		—			—			1,358
Accumulated loss in excess of equity investments		686,209			—			—		—			(686,209	)		—
Intercompany payables		—			—			1,721,211		—			(1,721,211	)		—
Other liabilities		—			5,332			—		3,038			—			8,370
Total Liabilities		1,065,577			3,673,466			2,030,366		2,002,232			(3,352,090	)		5,419,551
Stockholders’ Equity
Preferred stock
7.25% Convertible perpetual preferred stock		—			—			—		—			—			—
5.625% Convertible perpetual preferred stock		1			—			—		—			—			1
Common stock		472			1					12			(13	)		472
Additional paid-in capital		1,843,918			2,252,142			78,599		7,377,784			(9,708,525	)		1,843,918
Accumulated earnings (deficit)		(2,573,113	)		(2,597,052	)		72,324		(4,159,411	)		6,684,139			(2,573,113	)
Total Stockholders’ Equity		(728,722	)		(344,909	)		150,923		3,218,385			(3,024,399	)		(728,722	)
Total Liabilities and Stockholders’ Equity	$	336,855		$	3,328,557		$	2,181,289	$	5,220,617		$	(6,376,489	)	$	4,690,829

161

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 23 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

	For the Year Ended June 30, 2016
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
	(In thousands)
Revenues
Oil sales	$	—		$	—		$	317,867		$	264,895		$	(35,996	)	$	546,766
Natural gas sales		—			—			33,515			35,740			—			69,255
Gain on derivative financial instruments		—			86,731			91			3,684			—			90,506
Total Revenues		—			86,731			351,473			304,319			(35,996	)		706,527
Costs and Expenses
Lease operating		—			4,804			210,203			167,062			(35,996	)		346,073
Production taxes		—			14			1,083			345			—			1,442
Gathering and transportation		—			—			56,223			—			(298	)		55,925
Depreciation, depletion and amortization		—			—			173,201			172,648			(6,333	)		339,516
Accretion of asset retirement obligations		—			—			38,040			27,398			(748	)		64,690
Impairment of oil and natural gas properties		—			—			1,816,420			941,457			55,693			2,813,570
General and administrative expense		8,807			13,660			43,085			37,184			—			102,736
Total Costs and Expenses		8,807			18,478			2,338,255			1,346,094			12,318			3,723,952
Operating Income (Loss)		(8,807	)		68,253			(1,986,782	)		(1,041,775	)		(48,314	)		(3,017,425	)
Other Income (Expense)
Loss from equity method investees		(1,895,680	)		(2,836,003	)		(9,687	)		(1,885,623	)		6,616,247			(10,746	)
Other income, net		13,561			28,609			7			16,511			(55,092	)		3,596
Gain on early extinguishment of debt		33,203			1,193,396			—			21,269			277,728			1,525,596
Interest expense		(57,039	)		(329,641	)		(64	)		(93,245	)		74,331			(405,658	)
Total Other Income (Expense), net		(1,905,955	)		(1,943,639	)		(9,744	)		(1,941,088	)		6,913,214			1,112,788
Income (Loss) Before Reorganization Items and Income Taxes		(1,914,762	)		(1,875,386	)		(1,996,526	)		(2,982,863	)		6,864,900			(1,904,637	)
Reorganization items, net		(42	)		(9,178	)		(13	)		(4,968	)		—			(14,201	)
Income (Loss) Before Income Taxes		(1,914,804	)		(1,884,564	)		(1,996,539	)		(2,987,831	)		6,864,900			(1,918,838	)
Income Tax Expense (Benefit)		3,947			—			—			(87	)		(3,947	)		(87	)
Net Income (Loss)		(1,918,751	)		(1,884,564	)		(1,996,539	)		(2,987,744	)		6,868,847			(1,918,751	)
Preferred Stock Dividends		8,394			—			—			—			—			8,394
Net Income (Loss) Attributable to Common Stockholders	$	(1,927,145	)	$	(1,884,564	)	$	(1,996,539	)	$	(2,987,744	)	$	6,868,847		$	(1,927,145	)

162

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 23 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

	For the Year Ended June 30, 2015
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
	(In thousands)
Revenues
Oil sales	$	—		$	—		$	591,349		$	469,102		$	(7,720	)	$	1,052,731
Natural gas sales		—			—			67,169			50,113			—			117,282
Loss on derivative financial instruments		—			195,357			—			40,082			—			235,439
Total Revenues		—			195,357			658,518			559,297			(7,720	)		1,405,452
Costs and Expenses
Lease operating		—			296			246,904			208,615			7,720			463,535
Production taxes		—			33			3,333			5,019			—			8,385
Gathering and transportation		—			—			21,144			—			—			21,144
Depreciation, depletion and amortization		—			—			362,421			333,654			9,446			705,521
Accretion of asset retirement obligations		—			—			26,448			23,633			—			50,081
Impairment of oil and natural gas properties		—			—			842,621			1,699,590			(120,327	)		2,421,884
Goodwill impairment		—			—			—			329,293			—			329,293
General and administrative expense		8,409			11,801			56,985			39,305			—			116,500
Total Costs and Expenses		8,409			12,130			1,559,856			2,639,109			(103,161	)		4,116,343
Operating Income (Loss)		(8,409	)		183,227			(901,338	)		(2,079,812	)		95,441			(2,710,891	)
Other Income (Expense)
Loss from equity method investees		(2,415,367	)		(2,601,331	)		—			(2,527,727	)		7,527,260			(17,165	)
Other income (expense) – net		20,530			14,898			—			17,849			(49,101	)		4,176
Interest expense		(24,669	)		(256,918	)		(2,914	)		(87,908	)		49,101			(323,308	)
Total Other Income (Expense)		(2,419,506	)		(2,843,351	)		(2,914	)		(2,597,786	)		7,527,260			(336,297	)
Income (Loss) Before Income Taxes		(2,427,915	)		(2,660,124	)		(904,252	)		(4,677,598	)		7,622,701			(3,047,188	)
Income Tax Expense (Benefit)		5,923			(149,562	)		—			(445,536	)		(24,175	)		(613,350	)
Net Income (Loss)		(2,433,838	)		(2,510,562	)		(904,252	)		(4,232,062	)		7,646,876			(2,433,838	)
Preferred Stock Dividends		11,468			—			—			—			—			11,468
Net Income (Loss) Attributable to Common Stockholders	$	(2,445,306	)	$	(2,510,562	)	$	(904,252	)	$	(4,232,062	)	$	7,646,876		$	(2,445,306	)

163

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 23 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

	For the Year Ended June 30, 2014
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
	(In thousands)
Revenues
Oil sales	$	—		$	—		$	1,046,263		$	57,945		$	—		$	1,104,208
Natural gas sales		—			—			132,225			3,658			—			135,883
Loss on derivative financial instruments		—			(75,889	)		—			(11,079	)		—			(86,968	)
Total Revenues		—			(75,889	)		1,178,488			50,524			—			1,153,123
Costs and Expenses
Lease operating		—			(325	)		348,027			18,045			—			365,747
Production taxes		—			51			4,716			660			—			5,427
Gathering and transportation		—			—			23,532			—			—			23,532
Depreciation, depletion and amortization		—			—			389,793			26,340			(2,107	)		414,026
Accretion of asset retirement obligations		—			—			28,161			2,022			—			30,183
General and administrative expense		7,380			1,134			81,380			6,508			—			96,402
Total Costs and Expenses		7,380			860			875,609			53,575			(2,107	)		935,317
Operating Income (Loss)		(7,380	)		(76,749	)		302,879			(3,051	)		2,107			217,806
Other Income (Expense)
Income from equity method investees		26,009			299,556			—			91,741			(422,537	)		(5,231	)
Other income (expense) – net		19,923			1,954			—			17,808			(36,387	)		3,298
Interest expense		(14,485	)		(138,336	)		(5,957	)		(40,337	)		36,387			(162,728	)
Total Other Income (Expense)		31,447			163,174			(5,957	)		69,212			(422,537	)		(164,661	)
Income (Loss) Before Income Taxes		24,067			86,425			296,922			66,161			(420,430	)		53,145
Income Tax Expense (Benefit)		5,942			29,989			—			(911	)		—			35,020
Net Income (Loss)		18,125			56,436			296,922			67,072			(420,430	)		18,125
Preferred Stock Dividends		11,489			—			—			—			—			11,489
Net Income (Loss) Attributable to Common Stockholders	$	6,636		$	56,436		$	296,922		$	67,072		$	(420,430	)	$	6,636

164

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 23 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
(Debtor-in-Possession)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

	For the Year Ended June 30, 2016
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
	(In Thousands)
Cash Flows From Operating Activities
Net loss	$	(1,918,751	)	$	(1,884,564	)	$	(1,996,539	)	$	(2,987,744	)	$	6,868,847		$	(1,918,751	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		—			—			173,201			172,648			(6,333	)		339,516
Impairment of oil and natural gas properties		—			—			1,816,420			941,457			55,693			2,813,570
Deferred income tax expense (benefit)		3,947			—			—			—			(3,947	)		—
Change in fair value of derivative financial instruments		—			20,736			—			(1,573	)		—			19,163
Accretion of asset retirement obligations		—			—			38,040			27,398			(748	)		64,690
Loss from equity method investees		1,895,680			2,836,003			9,687			1,885,623			(6,616,247	)		10,746
Gain on early extinguishment of debt		(33,203	)		(1,193,396	)		—			(21,269	)		(277,728	)		(1,525,596	)
Amortization and write-off of debt issuance costs and other		47,699			106,097			63			(26,248	)		10,862			138,473
Deferred rent		—			—			—			9,154			—			9,154
Provision for loss on accounts receivable		—			—			—			3,200			—			3,200
Stock-based compensation		1,336			—			—			—			—			1,336
Changes in operating assets and liabilities																	—
Accounts receivable		622			18,318			36,580			(13,156	)		378			42,742
Prepaid expenses and other current assets		(1,729	)		(26,071	)		(388	)		3,750			—			(24,438	)
Settlement of asset retirement obligations		—			—			(13,123	)		(65,150	)		—			(78,273	)
Accounts payable and accrued liabilities		(6,485	)		(181,443	)		38,782			144,426			(57,467	)		(62,187	)
Net Cash Provided by (Used in) Operating Activities		(10,884	)		(304,320	)		102,723			72,516			(26,690	)		(166,655	)
Cash Flows from Investing Activities
Acquisitions, net of cash		—			—			(2,797	)		—			—			(2,797	)
Capital expenditures		—			(208	)		(80,733	)		(27,809	)		(3,134	)		(111,884	)
Insurance payments received		—			—			8,251			—			—			8,251
Change in equity method investments		—			—			—			—			—			—
Intercompany investment		—			(26,451	)		—			—			26,451			—
Transfers (to) from restricted cash		—			4,902			—			(27,038	)		—			(22,136	)
Proceeds from the sale of properties		—			15			5,243			435			—			5,693
Other		—			—			—			(40	)		—			(40	)
Net Cash (Used in) Provided by Investing Activities		—			(21,742	)		(70,036	)		(54,452	)		23,317			(122,913	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		334			—			—			—			—			334
Dividends to shareholders – preferred		(5,673	)		—			—			—			—			(5,673	)
Proceeds from long-term debt		—			1,121			—			—			—			1,121
Payments on long-term debt		—			(213,148	)		—			(13,736	)		(1,000	)		(227,884	)
Payment of debt assumed in acquisition								(25,187	)		—			—			(25,187	)
Fees related to debt extinguishment					(3,526	)		—			—			—			(3,526	)
Debt issuance costs		—			(1,826	)		—			(337	)		—			(2,163	)
Other		—			(1,000	)					(4,177	)		4,133			(1,044	)
Net Cash Provided by (Used in) Financing Activities		(5,339	)		(218,379	)		(25,187	)		(18,250	)		3,133			(264,022	)
Net (Decrease) Increase in Cash and Cash Equivalents		(16,223	)		(544,441	)		7,500			(186	)		(240	)		(553,590	)
Cash and Cash Equivalents, beginning of period		37,053			719,609			—			186			—			756,848
Cash and Cash Equivalents, end of period	$	20,830		$	175,168		$	7,500		$	—		$	(240	)	$	203,258

165

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 23 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
(Debtor-in-Possession)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

	For the Year Ended June 30, 2015
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
	(In Thousands)
Cash Flows From Operating Activities
Net income (loss)	$	(2,433,838	)	$	(2,510,562	)	$	(904,252	)	$	(4,232,062	)	$	7,646,876		$	(2,433,838	)
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		—			—			362,421			333,654			9,446			705,521
Impairment of oil and natural gas properties		—			—			842,621			1,699,590			(120,327	)		2,421,884
Goodwill impairment		—			—			—			329,293			—			329,293
Deferred income tax expense (benefit)		4,989			(149,563	)		—			(445,635	)		(24,174	)		(614,383	)
Change in derivative financial instruments		—			(40,929	)		—			(11,107	)		—			(52,036	)
Accretion of asset retirement obligations		—			—			26,448			23,633			—			50,081
Loss from equity method investees		2,415,367			2,601,331			—			2,527,727			(7,527,260	)		17,165
Amortization and write-off of debt issuance costs and other		12,670			21,530			—			(10,953	)		—			23,247
Stock-based compensation		4,124			—			—			—			—			4,124
Changes in operating assets and liabilities
Accounts receivable		(614	)		4,036			59,637			(11,891	)		116			51,284
Prepaid expenses and other current assets		(49	)		14,494			1,012			32,605			—			48,062
Settlement of asset retirement obligations		—			—			(47,923	)		(58,650	)		—			(106,573	)
Accounts payable and accrued liabilities		(17,729	)		(272,935	)		(24,768	)		34,213			168,141			(113,078	)
Net Cash Provided by (Used in) Operating Activities		(15,080	)		(332,598	)		315,196			210,417			152,818			330,753
Cash Flows from Investing Activities
Acquisitions, net of cash		—			—			(301	)		—			—			(301	)
Capital expenditures		—			—			(325,836	)		(397,993	)		—			(723,829	)
Insurance payments received		—			—			3,230			690			—			3,920
Change in equity method investments		—			—			—			12,642			—			12,642
Intercompany investment		(50,000	)		289,999			—			(86,999	)		(153,000	)		—
Transfers to restricted cash		—			(10,000	)		325			(5,001	)		—			(14,676	)
Proceeds from the sale of properties		—			—			7,386			9,545			245,000			261,931
Other		—			—			—			(135	)		—			(135	)
Net Cash Used in (Provided by) Investing Activities		(50,000	)		279,999			(315,196	)		(467,251	)		92,000			(460,448	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		2,336			—			—			—			—			2,336
Dividends to shareholders – common		(24,436	)		—			—			—			—			(24,436	)
Dividends to shareholders – preferred		(11,468	)		—			—			—			—			(11,468	)
Cash restricted under revolving credit facility related to property sold		—			(21,000	)		—			—			—			(21,000	)
Proceeds from long-term debt		—			2,261,572			—			570,000			(245,000	)		2,586,572
Payments on long-term debt		—			(1,429,885	)		—			(317,964	)		—			(1,747,849	)
Debt issuance costs		—			(42,202	)		—			(1,150	)		—			(43,352	)
Other		(2	)		—			—			(246	)		182			(66	)
Net Cash Provided by (Used in) Financing Activities		(33,570	)		768,485			—			250,640			(244,818	)		740,737
Net (Decrease) Increase in Cash and Cash Equivalents		(98,650	)		715,886			—			(6,194	)		—			611,042
Cash and Cash Equivalents, beginning of period		135,703			3,723			—			6,380			—			145,806
Cash and Cash Equivalents, end of period	$	37,053		$	719,609		$	—		$	186		$	—		$	756,848

166

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2016

Note 23 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
(Debtor-in-Possession)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

	For the Year Ended June 30, 2014
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
	(In Thousands)
Cash Flows From Operating Activities
Net income (loss)	$	18,125		$	56,436		$	296,922		$	67,072		$	(420,430	)	$	18,125
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		—			—			389,793			26,340			(2,107	)		414,026
Deferred income tax expense (benefit)		2,301			29,989			—			(911	)		—			31,379
Change in derivative financial instruments		—			60,037			—			9,619			—			69,656
Accretion of asset retirement obligations		—			—			28,161			2,022			—			30,183
Loss from equity method investees		(26,009	)		(299,556	)		—			(91,741	)		422,537			5,231
Amortization and write-off of debt issuance costs and other		7,219			6,555			—			—			—			13,774
Stock-based compensation		6,712			—			—			—			(1	)		6,711
Changes in operating assets and liabilities
Accounts receivable		(10	)		22,708			22,212			18,372			1			63,283
Prepaid expenses and other current assets		(18	)		19,746			23			(13,733	)		1			6,019
Settlement of asset retirement obligations		—			—			(57,391	)		—			—			(57,391	)
Accounts payable and accrued liabilities		(5,852	)		88,285			(256,890	)		1,284,956			(1,166,035	)		(55,536	)
Net Cash Provided by (Used in) Provided by Operating Activities		2,468			(15,800	)		422,830			1,301,996			(1,166,034	)		545,460
Cash Flows from Investing Activities
Acquisitions, net of cash		—			—			(37,657	)		(811,984	)		—			(849,641	)
Capital expenditures		—			16,746			(513,096	)		(292,326	)		—			(788,676	)
Insurance payments received		—			—			1,983			—			—			1,983
Change in equity method investments		—			—			—			(34,294	)		—			(34,294	)
Intercompany investment		(185,568	)		(979,420	)		—			(2,570	)		1,167,558			—
Transfers to restricted cash		—			—			(325	)		—			—			(325	)
Proceeds from the sale of properties		—			—			126,265			—			—			126,265
Other		—			—			—			113			—			113
Net Cash (Used in) Provided by Investing Activities		(185,568	)		(962,674	)		(422,830	)		(1,141,061	)		1,167,558			(1,544,575	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		3,994			—			—			—			—			3,994
Proceeds from convertible debt allocated to additional paid-in capital		63,432			—			—			—			—			63,432
Repurchase of company common stock		(30,824	)		—			—			(153,439	)		—			(184,263	)
Dividends to shareholders – common		(34,680	)		—			—			—			—			(34,680	)
Dividends to shareholders – preferred		(11,489	)		—			—			—			—			(11,489	)
Proceeds from long-term debt		336,568			3,085,145			—			(840	)		—			3,420,873
Payments on long-term debt		—			(2,079,072	)		—			(413	)		—			(2,079,485	)
Debt issuance costs		(9,585	)		(23,876	)		—			—			—			(33,461	)
Other		53			—			—			—			(53	)		—
Net Cash Provided by (Used in) Financing Activities		317,469			982,197			—			(154,692	)		(53	)		1,144,921
Net Increase in Cash and Cash Equivalents		134,369			3,723			—			6,243			1,471			145,806
Cash and Cash Equivalents, beginning of period		1,334			—			—			137			(1,471	)		—
Cash and Cash Equivalents, end of period	$	135,703		$	3,723		$	—		$	6,380		$	—		$	145,806

167

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

As previously reported in our Current Report on Form 8-K filed on December 4, 2014, on December 1, 2014, UHY LLP (“UHY”) informed the Company that its Texas practice had been acquired by BDO USA, LLP (“BDO”). As a result of this transaction, UHY resigned, effective as of December 1, 2014 (the “Resignation Date”), as the Company’s independent registered public accounting firm for the fiscal year ending June 30, 2015. UHY had served as the independent registered public accounting firm of Energy XXI Ltd for the fiscal year ended June 30, 2014. The Audit Committee of the Board of Directors of the Company (the “Audit Committee”) had selected UHY to serve as the Company’s independent registered public accounting firm for the fiscal year ending June 30, 2015. In addition, the shareholders of the Company approved and ratified that appointment at the Company’s Annual General Meeting on November 14, 2014.

During the Company’s two most recent fiscal years, previous to the acquisition of the UHY Texas practice by BDO, UHY’s audit reports on the Company’s consolidated financial statements did not contain an adverse opinion or disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles.

During the Company’s two most recent fiscal years of BDO acquiring the UHY Texas practice and the subsequent interim period through the Resignation Date, the Company and UHY did not have any disagreements on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which, if not resolved to the satisfaction of UHY, would have caused UHY to make reference to the matter in its reports on the Company’s consolidated financial statements during such periods; and there were no “reportable events” as the term is described in Item 304(a)(1)(v) of Regulation S-K.

The Company requested UHY furnish a letter addressed to the Securities and Exchange Commission, pursuant to Item 304(a)(3) of Regulation S-K, stating whether or not UHY agrees with the above statements, which letter we filed as Exhibit 16.1 to our Current Report on Form 8-K filed on December 4, 2014.

The Audit Committee recommended and approved the engagement of BDO as the successor independent registered public accounting firm, effective upon the consummation of the merger on the Resignation Date. At no time during the Company’s fiscal years ended June 30, 2014 and 2013 and during any subsequent interim period through the Resignation Date, did the Company consult with BDO regarding (i) the application of accounting principles to a specific completed or contemplated transaction, or the type of audit opinion that might be rendered on the Company’s financial statements, and no written report or oral advice was provided to the Company that BDO concluded was an important factor considered by the Company in reaching a decision as to any accounting, auditing or financial reporting issue or (ii) any matter that was the subject of a disagreement as defined in Item 304(a)(1)(iv) and related instructions of Regulation S-K or a “reportable event” as described in Item 304(a)(1)(v) of Regulation S-K.

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) to the Securities Exchange Act of 1934, as amended (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 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.

168

Management’s Annual Report on Internal Control over Financial Reporting

Management’s Annual Report on Internal Control over Financial Reporting is included in Item 8 “Financial Statements and Supplementary Data” of this Form 10-K on page 89 and is incorporated herein by reference.

Changes in Internal Control over Financial Reporting

The Board of Directors implemented additional controls and procedures in response to a material weakness in its control environment identified during the preparation of its financial statements for the fiscal year ended June 30, 2015, including, but not limited to, strengthening the Company’s vendor procurement procedures to address any potential conflicts of interest that could arise between the Company and any of its vendors; amended the Company’s Code of Business Conduct and Ethics to, among other things, include explicit prohibitions and heightened disclosures addressing activities or personal interests that create or appear to create a conflict between personal interests and the interests of the Company and implement a new insider trading policy. The Company also implemented an enhanced comprehensive training program on these new procedures and policies. At the direction of the Board of Directors the Company created a formal Chief Compliance Officer position in order to implement these new policies and procedures and to conduct the new training and certification programs. The Chief Compliance Officer role includes working with the Company’s senior management and the Board of Directors to instill a culture of compliance and encourage Company personnel and Directors to take compliance issues seriously. All Company personnel are encouraged to report any issues or direct any questions to the Chief Compliance Officer. The Chief Compliance Officer communicates quarterly with the Board of Directors.

Other than the changes 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, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

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 “Leadership — 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 “Investors” 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.

169

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 Accountant 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.

Part IV

Item 15. Exhibits, Financial Statement Schedules

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

(1) Financial Statements

	Page
Management’s Report on Internal Control over Financial Reporting		89
Report of Independent Registered Public Accounting Firm		90
Report of Independent Registered Public Accounting Firm		91
Report of Independent Registered Public Accounting Firm		92
Consolidated Financial Statements
Consolidated Balance Sheets as of June 30, 2016 and 2015		93
Consolidated Statements of Operations for the Years Ended June 30, 2016, 2015 and 2014		95
Consolidated Statements of Stockholders’ Equity for the Years Ended June 30, 2016, 2015 and 2014		96
Consolidated Statements of Cash Flows for the Years Ended June 30, 2016, 2015 and 2014		97
Notes to Consolidated Financial Statements		98

(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.

170

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONDENSED BALANCE SHEETS
(In Thousands)

	June 30,
	2016			2015
ASSETS
Current assets	$	21,144		$	37,955
Intercompany receivable		179,362			122,039
Intercompany notes receivable		171,000			171,000
Other assets and debt issuance costs, net of accumulated amortization		1,697			5,861
Total Assets	$	373,203		$	336,855
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities		12			25,150
Accumulated losses in excess of equity investments		2,585,839			686,209
Deferred income taxes		28,121			—
Long-term debt		—			354,218
Total Liabilities Not Subject to Compromise		2,613,972			1,065,577
Liabilities subject to compromise		413,316			—
Total Liabilities		3,027,288			1,065,577
Stockholders’ deficit		(2,654,085	)		(728,722	)
Total Liabilities and Stockholders’ Deficit	$	373,203		$	336,855

 
 
See accompanying Notes to Condensed Financial Statements

171

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONDENSED STATEMENT OF OPERATIONS
(In Thousands)

	Year Ended June 30,
	2016			2015			2014
Operating Expenses
General and administrative expense	$	8,807		$	8,409		$	7,380
Operating Loss		8,807			8,409			7,380
Other Income (Expense)
Income (loss) from equity method investees		(1,895,680	)		(2,415,367	)		26,009
Interest income		9,829			16,798			16,788
Interest expense		(57,039	)		(24,669	)		(14,485	)
Gain on early extinguishment of debt		33,203			—			—
Guarantee income		3,732			3,732			3,135
Total Other Income (Loss)		(1,905,955	)		(2,419,506	)		31,447
Income (Loss) Before Income Taxes and Reorganization Items		(1,914,762	)		(2,427,915	)		24,067
Reorganization items, net		(42	)		—			—
Income (Loss) Before Income Taxes		(1,914,804	)		(2,427,915	)		24,067
Income Tax Expense		3,947			5,923			5,942
Net Income (Loss)	$	(1,918,751	)	$	(2,433,838	)	$	18,125

 
 
See accompanying Notes to Condensed Financial Statements

172

ENERGY XXI LTD
(Debtor-in-Possession)
 
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)

	Year Ended June 30,
	2016			2015			2014
Cash Flows From Operating Activities
Net income (loss)	$	(1,918,751	)	$	(2,433,838	)	$	18,125
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Gain on early extinguishment of debt		(33,203	)		—			—
Stock-based compensation and deferred income tax expense		5,283			9,113			9,013
Amortization of debt issuance costs and other		47,699			12,670			7,219
Income from equity method investees		1,895,680			2,415,367			(26,009	)
Changes in operating assets and liabilities		(7,592	)		(18,392	)		(5,880	)
Net Cash Provided by (Used in) Operating Activities		(10,884	)		(15,080	)		2,468
Cash Flows from Investing Activities
Change in equity method investments		—			(50,000	)		(185,568	)
Net Cash Used in Investing Activities		—			(50,000	)		(185,568	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		334			2,336			3,994
Repurchase of company common stock		—			—			(30,824	)
Dividends to shareholders		(5,673	)		(35,904	)		(46,169	)
Debt issuance costs		—			—			(9,585	)
Proceeds from convertible debt allocated to additional paid-in capital		—			—			63,432
Proceeds from long-term debt		—			—			336,568
Other		—			(2	)		53
Net Cash Provided by (Used in) Financing Activities		(5,339	)		(33,570	)		317,469
Net Increase (Decrease) in Cash and Cash Equivalents		(16,223	)		(98,650	)		134,369
Cash and Cash Equivalents, beginning of year		37,053			135,703			1,334
Cash and Cash Equivalents, end of year	$	20,830		$	37,053		$	135,703

 
 
See accompanying Notes to Condensed Financial Statements

173

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONDENSED FINANCIAL STATEMENTS

Note 1 — Basis of Presentation and Chapter 11 Proceedings

These condensed parent only financial statements of Energy XXI Ltd (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 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, 2016, substantially all the net assets of the Company’s subsidiaries were restricted. 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.

Bankruptcy Proceedings and Restructuring Support Agreement

On April 14, 2016 (the “Petition Date”), Energy XXI Ltd, Energy XXI Gulf Coast, Inc., an indirect wholly-owned subsidiary of Energy XXI Ltd (“EGC”), EPL Oil & Gas, Inc., an indirect wholly-owned subsidiary of Energy XXI Ltd (“EPL”) and certain other subsidiaries of Energy XXI Ltd (together with Energy XXI Ltd, EGC and EPL, the “Debtors”) (excluding Energy XXI GIGS Services, LLC which leases a subsea pipeline gathering system located in the shallow Gulf of Mexico Shelf and storage and onshore processing facilities on Grand Isle, Louisiana, Energy XXI Insurance Limited through which certain insurance coverage for its operations is obtained by the Company, Energy XXI (US Holdings) Limited, Energy XXI International Limited, Energy XXI Malaysia Limited and Energy XXI M21K, LLC, (together, the “Non-Debtors”)) filed voluntary petitions for reorganization (the petitions collectively, the “Bankruptcy Petitions”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) seeking relief under the provisions of chapter 11 of Title 11 (“Chapter 11”) of the United States Bankruptcy Code (the “Bankruptcy Code”). The Debtors’ Chapter 11 cases (collectively, the “Chapter 11 Cases”) are being jointly administered under the caption “In re: Energy XXI Ltd, et al., Case No. 16-31928.” The Debtors continue to operate their businesses and manage their assets as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Concurrently with the filing of the Bankruptcy Petitions and to streamline the business operations and organization structure following the emergence from Chapter 11 proceedings, Energy XXI Ltd filed a petition to commence an official dissolution proceeding under the laws of Bermuda before the Supreme Court of Bermuda (the “Bermuda Proceeding”). On April 15, 2016, John C. McKenna was appointed as provisional liquidator by the Supreme Court of Bermuda. The Bermuda Proceeding is a limited ancillary proceeding under which dissolution of Energy XXI Ltd will be completed following the confirmation of the Plan by the Bankruptcy Court, accordingly, the Bankruptcy Court retains primary jurisdiction over Energy XXI Ltd during the Chapter 11 Cases. On June 3, 2016, the Bermuda Court granted the Debtors’ request to adjourn the Bermuda Proceeding through November 4, 2016.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. However, the Chapter 11 Cases and sustained depressed commodity prices raise substantial doubt about our ability to continue as a going concern.

These condensed parent only financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern.

174

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONDENSED FINANCIAL STATEMENTS

Note 1 — Basis of Presentation and Chapter 11 Proceedings  – (continued)

Presentation

For periods subsequent to filing the Bankruptcy Petitions, we have prepared our consolidated financial statements in accordance with ASC 852, Reorganizations. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Pre-petition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

Liabilities Subject to Compromise

Liabilities subject to compromise represent liabilities incurred prior to the commencement of the bankruptcy proceedings which may be affected by the Chapter 11 process. These amounts represent the Company’s allowed claims and its best estimate of claims expected to be allowed which will be resolved as part of the bankruptcy proceedings. Such claims remain subject to future adjustments. Adjustments may result from negotiations, actions of the Bankruptcy Court, determination as to the value of any collateral securing claims, or other events. Differences between liability amounts estimated by the Company and claims filed by creditors are being investigated and the Bankruptcy Court will make a final determination of the allowable claims. Liabilities subject to compromise consist of the following (in thousands):

	June 30, 2016
Debt	$	363,018
Intercompany payable		43,536
Accrued liabilities		6,762
Total liabilities subject to compromise	$	413,316

Interest Expense

The Company has discontinued recording interest on debt classified as liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the statements of operations was approximately $2.3 million, representing interest expense from the Petition Date through June 30, 2016.

Reorganization Items

Reorganization items represent the direct and incremental costs of being in bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated. Reorganization items consist of the following for the year ended June 30, 2016 (in thousands):

	Year Ended June 30, 2016
Professional fees	$	42
Total reorganization items	$	42

175

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONDENSED FINANCIAL STATEMENTS

Note 2 — Notes Receivable

The Company has advanced $171.0 million under promissory notes to its wholly owned subsidiary, which bears a simple interest rate of 9.75% per annum. Interest on notes receivable amounted to approximately $16.7 million for each of the years ended June 30, 2016, June 30, 2015 and June 30, 2014.

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 were recorded as debt issuance costs. 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 accordingly 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 3.0% 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 3.0% Senior Convertible Notes which has been reflected as additional paid-in capital. Based on applying the implied straight debt rate, the $400 million aggregate principal amount of the 3.0% Senior Convertible Notes was recorded at $336.6 million and the original issue discount of $63.4 million was amortized as an increase in interest expense on the 3.0% Senior Convertible Notes.

As described in the indenture governing the 3.0% Senior Convertible Notes, the 3.0% Senior Convertible Notes can be converted in multiples of $1,000 principal amount, upon request by the bondholder, if prior to September 15, 2018, during the five consecutive business-day period following any ten consecutive trading-day period in which the trading price per $1,000 principal amount of 3.0% Senior Convertible Notes for each trading day during such ten trading-day period was less than 98% of the closing sale price of our common stock for each trading day during such ten trading-day period multiplied by the then current conversion rate. In March 2016, each $1,000 principal amount of 3.0% Senior Convertible Notes were trading substantially lower than 98% of the value of our common stock multiplied by the then current conversion rate. Accordingly, certain bondholders holding $37 million in face value of our 3.0% Senior Convertible Notes requested conversion into shares of our common stock. Upon conversion, we elected to issue shares of our common stock and delivered 915,385 shares of our common stock with fractional shares settled in cash. We followed the guidance in ASC 470-20, Debt with Conversion and Other Options, to record such conversion which allows for the allocation of fair value of the consideration transferred to the bondholder between the liability and equity components of the original instrument, recognition of gain or loss on debt extinguishment and allocation of remaining consideration transferred to reacquire the equity component. Accordingly, we recorded a debt extinguishment gain of approximately $33.2 million and proportionately adjusted the related debt issue costs, accrued interest and original debt issue discount.

The filing of the Bankruptcy Petitions constituted an event of default with respect to our existing debt obligations. Accordingly the Company’s pre-petition unsecured indebtedness under 3.0% Senior Convertible Notes became immediately due and payable and any efforts to enforce such payment obligations are automatically stayed as a result of the Chapter 11 Cases. In addition, as a result of the covenant violations that existed at March 31, 2016 that were not cured prior to the filing of the Bankruptcy Petitions, our outstanding indebtedness under the 3.0% Senior Convertible Notes was classified as current in the consolidated balance sheet at March 31, 2016, and we accelerated the amortization of the associated original issue discount,

176

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONDENSED FINANCIAL STATEMENTS

Note 3 — Long-Term Debt  – (continued)

fully amortizing those amounts as of March 31, 2016. In addition, we accelerated the amortization of the remaining debt issuance costs related to 3.0% Senior Convertible Notes, fully amortizing those costs as of March 31, 2016.

On the Petition Date, the Debtors filed the Bankruptcy Petitions, which constituted an event of default under the indenture governing the 3.0% Senior Convertible Notes and accelerated the indebtedness thereunder.

Note 4 — Guarantee

The Company has guaranteed the obligations under the lease agreement entered into by its wholly owned subsidiary under which such subsidiary will operate the Grand Isle Gathering System (the “GIGS Lease”). The primary term of the GIGS Lease is 11 years, with one renewal option, which will be the lesser of nine years or 75% of the expected remaining useful life of the Grand Isle Gathering System. The operating lease utilizes a minimum rent plus a variable rent structure, which is linked to the oil revenues realized from the Grand Isle Gathering System above a predetermined oil revenue threshold. The aggregate annual minimum cash monthly payments for the first twelve months of the GIGS Lease total $31.5 million, and such payment amounts average $40.5 million per year over the life of the lease.

Note 5 — 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.

Note 6 — Stockholders’ Equity

Our common stock traded on the NASDAQ under the symbol “EXXI” prior to the delisting of our common stock in connection with the commencement of the Chapter 11 proceedings. Our common stock resumed trading on the OTC Pink under the symbol “EXXIQ” on April 25, 2016. 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.

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.

In March 2016, each $1,000 principal amount of 3.0% Senior Convertible Notes were trading substantially lower than 98% of the value of our common stock multiplied by the then current conversion rate. Accordingly, certain bondholders holding $37 million in face value of our 3.0% Senior Convertible Notes requested conversion into shares of our common stock. Upon conversion, we elected to issue shares of our common stock and delivered 915,385 shares of our common stock with fractional shares settled in cash. For more information see Note 3 — “Long-Term Debt”.

177

ENERGY XXI LTD
(Debtor-in-Possession)
 
NOTES TO CONDENSED FINANCIAL STATEMENTS

Note 6 — Stockholders’ Equity  – (continued)

Pursuant to the Restructuring Support Agreement entered into on April 11, 2016, it is expected that an order of the Bermuda court will be sought to dissolve Energy XXI Ltd under the laws of Bermuda concurrently with the Company’s emergence from the Chapter 11 proceedings, and (assuming that there are no assets available for distribution to equity under the Bermuda laws governing the payment of stakeholders in a Bermuda dissolution), existing equity holders would not receive distribution in respect of their equity interests in that dissolution. Accordingly any trading in shares of our common and preferred stock during the pendency of the Chapter 11 proceedings is highly speculative. In addition, as of April 14, 2016, we are no longer accruing dividends on preferred stock. Energy XXI suspended the quarterly dividends on the 5.625% Preferred Stock and the 7.25% Preferred Stock for the six months ended June 30, 2016, and, as a result, no dividends for the fiscal third or fourth quarter were paid to the holders of either series of preferred stock.

Note 7 — Supplemental Cash Flow Information

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

	Year Ended June 30,
	2016		2015		2014
Cash paid for interest	$	6,275	$	12,000	$	6,767

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

	Year Ended June 30,
	2016		2015		2014
Common stock issued for the EPL Acquisition, net	$	—	$	—	$	315,394

(2) 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.

178

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 27^th day of September 2016.

ENERGY XXI LTD

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

John D. Schiller, Jr.
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.	Director and Chief Executive Officer (Principal Executive Officer)	September 27, 2016
/s/ BRUCE W. BUSMIRE Bruce W. Busmire	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	September 27, 2016
/s/ JAMES LACHANCE James LaChance	Chairman of the Board	September 27, 2016
/s/ WILLIAM COLVIN William Colvin	Director	September 27, 2016
/s/ CORNELIUS DUPRÉ II Cornelius Dupré II	Director	September 27, 2016
/s/ HILL A. FEINBERG Hill A Feinberg	Director	September 27, 2016
/s/ KEVIN S. FLANNERY Kevin S. Flannery	Director	September 27, 2016
/s/ SCOTT A. GRIFFITHS Scott A. Griffiths	Director	September 27, 2016

179

EXHIBIT INDEX

Exhibit Number	Exhibit 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
2.3	Purchase and Sale Agreement, dated June 22, 2015, by and between Grand Isle Corridor, LP and Energy XXI USA, Inc.	2.1 to the Company’s Form 8-K filed on June 23, 2015	001-33628
2.4	Guaranty, dated June 22, 2015, by Energy XXI Ltd in favor of Grand Isle Corridor, LP	2.2 to the Company’s Form 8-K filed on June 23, 2015	001-33628
2.5	Guaranty, dated June 22, 2015, by CorEnergy Infrastructure Trust, Inc. in favor of Energy XXI USA, Inc.	2.3 to the Company’s Form 8-K filed on June 23, 2015	001-33628
3.1	Altered Memorandum of Association of Energy XXI Ltd	3.1 to the Company’s Form 8-K filed on November 9, 2011	001-33628
3.2	Bye-Laws of Energy XXI Ltd	3.2 to the Company’s Form 8-K filed on November 9, 2011	001-33628
3.3	Certificate of Designations of Series C Junior Participating Preferred Shares of Energy XXI Ltd	3.1 to the Company’s Form 8-K filed on February 16, 2016	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 the Company’s 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 the Company’s Form 8-K filed on February 28, 2011	001-33628

180

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
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
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

181

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
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
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
4.16	Indenture, related to the 11.000% Senior Secured Second Lien Notes due 2020, dated as of March 12, 2015, by and among Energy XXI Gulf Coast, Inc., the Guarantors named therein and U.S. Bank National Association, as Trustee	10.1 to the Company’s Form 8-K filed on March 17, 2015	001-33628
4.17	Rights Agreement dated as of February 15, 2016 between Energy XXI Ltd, as the Company, and Continental Stock Transfer & Trust Company, as Rights Agent	4.1 to the Company’s Form 8-K filed on February 16, 2016	001-33628
10.1†	Form of Restricted Stock Grant Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.6 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.2†	Form of Restricted Stock Unit Agreement (Chief Executive Officer) under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	4.4 to the Company’s Form S-8 filed on December 8, 2015	333-208389
10.3†	Form of Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	4.5 to the Company’s Form S-8 filed on December 8, 2015	333-208389
10.4†	Form of TSR Outperformance Restricted Stock Unit Agreement (Chief Executive Officer) under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	4.6 to the Company’s Form S-8 filed on December 8, 2015	333-208389

182

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.5†	Form of TSR Outperformance Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	4.7 to the Company’s Form S-8 filed on December 8, 2015	333-208389
10.6	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
10.7†	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 the Company’s Form 10-K filed on September 11, 2008	001-33628
10.8†	Energy XXI Services, LLC Directors’ Deferred Compensation Plan	10.1 to the Company’s Form 8-K filed on September 10, 2008	001-33628
10.9†	Employment Agreement of John D. Schiller, Jr., effective September 10, 2008	10.1 to the Company’s Form 8-K filed on September 11, 2008	001-33628
10.10†	First Amendment to Employment Agreement, dated as of October 15, 2015, by and between the Company and John D. Schiller, Jr.	10.1 to the Company’s Form 8-K filed on October 15, 2015	001-33628
10.11†	Form of Indemnification Agreement between Energy XXI (Bermuda) Limited and Indemnitees	10.1 to the Company’s Form 8-K filed on November 5, 2008	001-33628
10.12†	Form of Indemnification Agreement Between Company Subsidiaries and Indemnitees	10.2 to the Company’s Form 8-K filed on November 5, 2008	001-33628
10.13†	Energy XXI Services, LLC Employee Stock Purchase Plan	10.1 to the Company’s Form 8-K filed on November 5, 2008	001-33628
10.14†	Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan	4.2 to Form S-8 filed on June 10, 2009	333-159868
10.15†	Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Restricted Stock Unit Awards Agreement	10.20 to the Company’s Form 10-K filed on August 9, 2012	001-33628
10.16†	Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Performance Unit Awards Agreement	10.14 to the Company’s Form 10-K filed on August 25, 2014	001-33628
10.17†	Energy XXI Services, LLC, Employee Severance Plan (Amended and Restated August 1, 2014)	10.15 to the Company’s Form 10-K filed on August 25, 2014	001-33628
10.18†	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
10.19†	Energy XXI Services, LLC Long-Term Performance Cash Incentive Plan	10.7 to the Company’s Form 10-Q filed on February 16, 2016	001-33628

183

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.20†	Release and Separation Agreement, by and between David West Griffin and Energy XXI Ltd, dated December 4, 2014	10.1 to the Company’s Form 8-K filed on December 5, 2014	001-33628
10.21†	Release and Separation Agreement, by and between Benjamin Marchive and Energy XXI (Bermuda) Limited, dated August 20, 2014	10.2 to the Company’s Form 10-Q filed on February 9, 2015	001-33628
10.22	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 the Company’s Form 8-K filed on May 6, 2011	001-33628
10.23	First Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 4, 2011	10.1 to the Company’s Form 8-K filed on October 4, 2011	001-33628
10.24	Second Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 24, 2012	10.1 to the Company’s Form 8-K filed on May 25, 2012	001-33628
10.25	Third Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 19, 2012	10.1 to the Company’s Form 8-K filed on October 15, 2012	001-33628
10.26	Fourth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of April 9, 2013	10.1 to the Company’s Form 8-K filed on April 10, 2013	001-33628
10.27	Fifth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 1, 2013	10.1 to the Company’s Form 8-K filed on May 6, 2013	001-33628
10.28	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
10.29	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
10.30	Eighth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 23, 2014	10.25 to the Company’s form 10-K filed on August 25, 2014	001-33628
10.31	Waiver to Second Amended and Restated First Lien Credit Agreement, dated as of August 22, 2014	10.26 to the Company’s form 10-K filed on August 25, 2014	001-33628
10.32	Ninth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of September 5, 2015	10.1 to the Company’s Form 8-K filed on September 9, 2014	001-33628

184

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.33	Tenth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of March 3, 2015	10.2 to the Company’s Form 10-Q filed on May 8, 2015	001-33628
10.34	Eleventh Amendment and Waiver to Second Amended and Restated First Lien Credit Agreement, dated as of July 31, 2015	10.29 to the Company’s Form 10-K filed on September 29, 2015	001-33628
10.35	Twelfth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of November 30, 2015	10.1 to the Company’s Form 8-K filed on November 30, 2015	001-33628
10.36	Thirteenth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of February 29, 2016	10.1 to the Company’s Form 8-K filed on March 4, 2016	001-33628
10.37	Fourteenth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of March 14, 2016	10.1 to the Company’s Form 8-K filed on March 15, 2016	001-33628
10.38	Energy XXI Services, LLC Restoration Plan Amended and Restated effective January 1, 2013	10.1 to the Company’s Form 10-Q filed on January 31, 2013	001-33628
10.39	Interim Chief Strategic Officer Agreement, dated as of February 23, 2015, between Energy XXI Services, LLC and James LaChance.	10.1 to the Company’s Form 8-K filed on February 25, 2015	001-33628
10.40	Purchase Agreement, dated March 5, 2015, by and between Energy XXI Gulf Coast, Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC and Imperial Capital, LLC, as representatives of the Initial Purchasers, and the Guarantors named therein	10.1 to the Company’s Form 8-K filed on March 9, 2015	001-33628
10.41	Intercreditor Agreement, dated as of March 12, 2015, by and between U.S. Bank National Association, as Collateral Trustee, and the Royal Bank of Scotland plc, as Priority Lien Agent	10.1 to the Company’s Form 8-K filed on March 17, 2015	001-33628
10.42	Collateral Trust Agreement, dated as of March 12, 2015, by and among Energy XXI Gulf Coast, Inc., the Guarantors from time to time party thereto, U.S. Bank National Association, as Trustee, the other Parity Lien Debt Representatives from time to time party thereto and U.S. Bank National Association, as Collateral Trustee	10.2 to the Company’s Form 8-K filed on March 17, 2015	001-33628

185

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.43	Second Lien Pledge and Security Agreement and Irrevocable Proxy, dated as of March 12, 2015, by and among Energy XXI Gulf Coast, Inc., each Subsidiary Guarantor (as defined in the Indenture) party thereto and U.S. Bank National Association, as Collateral Trustee	10.3 to the Company’s Form 8-K filed on March 17, 2015	001-33628
10.44	Second Lien Pledge Agreement and Irrevocable Proxy, dated as of March 12, 2015, by and between Energy XXI USA, Inc. and U.S. Bank National Association, as Collateral Trustee	10.4 to the Company’s Form 8-K filed on March 17, 2015	001-33628
10.45	Second Lien Security Agreement relating to the Grand Isle Gathering System Assets, dated as of March 12, 2015, by and between Energy XXI USA, Inc. and U.S. Bank National Association, as Collateral Trustee	10.5 to the Company’s Form 8-K filed on March 17, 2015	001-33628
10.46	Secured Second Lien Promissory Note, dated as of March 12, 2015, issued by EPL Oil & Gas, Inc., as the Maker, in favor of Energy XXI Gulf Coast, Inc., as the Payee	10.6 to the Company’s Form 8-K filed on March 17, 2015	001-33628
10.47	Guaranty, dated as of March 12, 2015, issued by the subsidiaries of EPL Oil & Gas, Inc., in favor of Energy XXI Gulf Coast, Inc., as Lender	10.7 to the Company’s Form 8-K filed on March 17, 2015	001-33628
10.48	Second Lien Pledge and Security Agreement and Irrevocable Proxy, dated as of March 12, 2015, by EPL Oil & Gas, Inc. and each Subsidiary Guarantor Party thereto, in favor of Energy XXI Gulf Coast, Inc., as Lender	10.8 to the Company’s Form 8-K filed on March 17, 2015	001-33628
10.49	Intercompany Intercreditor Agreement, dated as of March 12, 2015, between the Royal Bank of Scotland plc, as Priority Lien Agent and Energy XXI Gulf Coast, Inc.	10.12 to the Company’s Form 10-Q filed on May 8, 2015	001-33628
10.50	Transportation Agreement, dated as of March 11, 2015, between Energy XXI Gulf Coast, Inc. and Energy XXI USA, Inc.	10.13 to the Company’s Form 10-Q filed on May 8, 2015	001-33628
10.51	Assignment and Bill of Sale, dated March 11, 2015, by and among Energy XXI GOM, LLC, Energy XXI Pipeline, LLC, Energy XXI Pipeline II, LLC, and Energy XXI USA, Inc.	10.14 to the Company’s Form 10-Q filed on May 8, 2015	001-33628
10.52	Lease, dated June 30, 2015, by and between Grand Isle Corridor, LP and Energy XXI GIGS Services, LLC	10.1 to the Company’s Form 8-K filed on July 1, 2015	001-33628

186

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.53	Waiver to Lease by and between Grand Isle Corridor, LP and Energy XXI GIGS Services, LLC, dated April 13, 2016	10.2 to the Company’s Form 8-K filed on April 14, 2016	001-33628
10.54	Restructuring Support Agreement by and among Energy XXI Ltd, Energy XXI Gulf Coast, Inc., EPL Oil & Gas, Inc., those certain additional subsidiaries of Energy XXI Ltd listed on Schedule 1 of the Restructuring Support Agreement and certain holders of the 11.000% senior secured second lien notes, dated April 11, 2016	10.1 to the Company’s Form 8-K filed on April 14, 2016	001-33628
10.55	First Amendment to Restructuring Support Agreement by and among Energy XXI Ltd, Energy XXI Gulf Coast, Inc., EPL Oil & Gas, Inc., those certain additional subsidiaries of Energy XXI Ltd listed on Schedule 1 of the Restructuring Support Agreement and certain holders of the 11.000% senior secured second lien notes, dated May 16, 2016	10.1 to the Company’s Form 8-K filed on May 20, 2016	001-33628
10.56	Second Amendment to Restructuring Support Agreement by and among Energy XXI Ltd, Energy XXI Gulf Coast, Inc., EPL Oil & Gas, Inc., those certain additional subsidiaries of Energy XXI Ltd listed on Schedule 1 of the Restructuring Support Agreement and certain holders of the 11.000% senior secured second lien notes, dated June 28, 2016	10.1 to the Company’s Form 8-K filed on July 5, 2016	001-33628
10.57	Third Amendment to Restructuring Support Agreement by and among Energy XXI Ltd, Energy XXI Gulf Coast, Inc., EPL Oil & Gas, Inc., those certain additional subsidiaries of Energy XXI Ltd listed on Schedule 1 of the Restructuring Support Agreement and certain holders of the 11.000% senior secured second lien notes, dated July 28, 2016	10.1 to the Company’s Form 8-K filed on August 1, 2016	001-33628
10.58	Fourth Amendment to Restructuring Support Agreement by and among Energy XXI Ltd, Energy XXI Gulf Coast, Inc., EPL Oil & Gas, Inc., those certain additional subsidiaries of Energy XXI Ltd listed on Schedule 1 of the Restructuring Support Agreement and certain holders of the 11.000% senior secured second lien notes, dated August 19, 2016	10.1 to the Company’s Form 8-K filed on August 23, 2016	001-33628

187

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.59	Fifth Amendment to Restructuring Support Agreement by and among Energy XXI Ltd, Energy XXI Gulf Coast, Inc., EPL Oil & Gas, Inc., those certain additional subsidiaries of Energy XXI Ltd listed on Schedule 1 of the Restructuring Support Agreement and certain holders of the 11.000% senior secured second lien notes, dated September 13, 2016	10.1 to the Company’s Form 8-K filed on September 13, 2016	001-33628
12.1	Ratio of Earnings (Loss) to Combined Fixed Charges and Preference Dividends — Energy XXI Ltd	Filed herewith
21.1	Subsidiary List	Filed herewith
23.1	Consent of BDO USA, LLP	Filed herewith
23.2	Consent of UHY, LLP	Filed herewith
23.3	Consent of Netherland, Sewell & Associates, Inc.	Filed herewith
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.1	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists	Filed herewith
101.INS	XBRL Instance Document	Filed herewith
101.SCH	XBRL Taxonomy Extension Schema Document	Filed herewith
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	Filed herewith
101.DEF	XBRL Taxonomy Extension Label Linkbase Document	Filed herewith
101.LAB	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	Filed herewith

188