UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-K

 

o	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended

or

x	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from July 1, 2016 to December 31, 2016

Commission file number: 000-1404973

 

Energy XXI Gulf Coast, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware	20-4278595
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1021 Main, Suite 2626 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713)-351-3000

 

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
Not Applicable	Not Applicable

Securities registered pursuant to Section 12(g) of the Act: Common Stock, par value $0.01 per share

 

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 o
Non-accelerated filer x	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 $4,283,465 based on the closing sale price of $0.05 per share as reported on The Pink Open Market on June 30, 2016, the last business day of the registrant’s most recently completed second fiscal quarter.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.Yes x No o

The number of shares of the registrant’s common stock outstanding on February 15, 2017 was 33,211,594.

DOCUMENTS INCORPORATED BY REFERENCE:

None

 

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		22
Item 1B Unresolved Staff Comments		44
Item 2 Properties		44
Item 3 Legal Proceedings		44
Item 4 Mine Safety Disclosures		44
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		45
Item 6 Selected Financial Data		46
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations		52
Item 7A Quantitative and Qualitative Disclosures About Market Risk		85
Item 8 Financial Statements and Supplementary Data		87
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		165
Item 9A Controls and Procedures		165
Item 9B Other Information		166
PART III
Item 10 Directors, Executive Officers and Corporate Governance		166
Item 11 Executive Compensation		174
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		188
Item 13 Certain Relationships and Related Transactions, and Director Independence		190
Item 14 Principal Accountant Fees and Services		190
PART IV
Item 15 Exhibits and Financial Statement Schedules		192
Item 16 Form 10-K Summary		192
Signatures		193

i

GLOSSARY OF TERMS

Bankruptcy Terms

On April 14, 2016 (the “Petition Date”), Energy XXI Ltd (“EXXI Ltd”), an exempt company incorporated under the laws of Bermuda and predecessor of the registrant under this transition report on Form 10-K for the six month transition period ended December 31, 2016 (this “Form 10-K”), Energy XXI Gulf Coast, Inc., then an indirect wholly-owned subsidiary of EXXI Ltd (“EGC”), EPL Oil & Gas Inc., an indirect wholly-owned subsidiary of EXXI Ltd (“EPL”) and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the United States Bankruptcy Court for the Southern District of Texas, Houston Division seeking relief under the provisions of chapter 11 of Title 11 of the United States Code.

In connection therewith, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to Energy XXI Gulf Coast, Inc. (the “Reorganized EGC”). On December 30, 2016 (the “Emergence Date”), the entities emerged from bankruptcy and shares of common stock and common stock warrants of Reorganized EGC were distributed to creditors of the Debtors’ (defined below) pursuant to the Plan (defined below). In accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), the Reorganized EGC was required to apply fresh start accounting upon EXXI Ltd’s emergence from bankruptcy and it evaluated transaction activity between the Emergence Date and December 31, 2016 and concluded that an accounting convenience date of December 31, 2016 (the “Convenience Date”) was appropriate.

As used throughout this Form 10-K, references to “Reorganized EGC”, the “Company,” “we,” “our”, “Successor”, “Successor Company” or similar terms when used in reference to the period subsequent to the emergence from the bankruptcy refer to Reorganized EGC, the new parent entity and successor issuer of EXXI Ltd pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). References in this Form 10-K to “EXXI Ltd,” “we,” “our”, “Predecessor”, “Predecessor Company” or similar terms when used in reference to the periods prior to the emergence from the bankruptcy refer to Energy XXI Ltd, the predecessor and former parent entity that will be dissolved upon the completion of the Bermuda Proceeding (as defined below). References in this Form 10-K to “EGC” refer to Energy XXI Gulf Coast, Inc. in the periods prior to the emergence from the bankruptcy during which it was the indirect wholly-owned operating subsidiary of EXXI Ltd.

Below is a list of additional terms relating to the bankruptcy as used throughout this Form 10-K:

Bankruptcy Code means title 11 of the United States Code, as amended and in effect during the pendency of the Chapter 11 Cases.

Bankruptcy Court means the United States Bankruptcy Court for the Southern District of Texas, Houston Division.

Bankruptcy Petitions means the Debtors’ voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11 under the caption In re Energy XXI Ltd, et al., Case No. 16-31928.

Bermuda Proceeding means the official liquidation proceeding for EXXI Ltd under the laws of Bermuda commenced pursuant to the winding-up petition before the Bermuda Court.

Bermuda Court means the Supreme Court of Bermuda.

Chapter 11 means chapter 11 of Title 11 of the Bankruptcy Code.

Chapter 11 Cases means the Debtors’ procedurally consolidated and jointly administered Chapter 11 cases in the Bankruptcy Court.

Confirmation Hearing means the hearing of the Bankruptcy Court to consider confirming the Plan pursuant to section 1129 of the Bankruptcy Code.

Confirmation Order means the order dated December 13, 2016 entered by the Bankruptcy Court approving and confirming the Plan pursuant to section 1129 of the Bankruptcy Code.

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Debtors means, collectively, the following: Anglo-Suisse Offshore Pipeline Partners, LLC, Delaware EPL of Texas, LLC, Energy Partners Ltd., LLC, Energy XXI GOM, LLC, Energy XXI Gulf Coast, Inc., Energy XXI Holdings, Inc., Energy XXI, Inc., Energy XXI Leasehold, LLC, Energy XXI Ltd, Energy XXI Natural Gas Holdings, Inc., Energy XXI Offshore Services, Inc., Energy XXI Onshore, LLC, Energy XXI Pipeline, LLC, Energy XXI Pipeline II, LLC, Energy XXI Services, LLC, Energy XXI Texas Onshore, LLC, Energy XXI USA, Inc., EPL of Louisiana, L.L.C., EPL Oil & Gas, Inc., EPL Pioneer Houston, Inc., EPL Pipeline, L.L.C., M21K, LLC, MS Onshore, LLC, Natural Gas Acquisition Company I, LLC, Nighthawk, L.L.C., and Soileau Catering, LLC.

Disclosure Statement means the Debtors’ Third Amended Disclosure Statement (as amended, modified, or supplemented from time to time).

Disclosure Statement Supplement means the solicitation version of the Second Supplement to the Disclosure Statement Setting Forth Modifications to the Plan (as amended, modified, or supplemented from time to time).

Emergence Date means December 30, 2016.

Convenience Date means December 31, 2016.

Non-Debtors means all of EXXI Ltd’s wholly and not-wholly owned subsidiaries who were not Debtors in the Chapter 11 Cases, including: (a) Energy XXI Insurance Limited; (b) Energy XXI M21K, LLC; (c) Energy XXI GIGS Services, LLC; (d) Energy XXI (US Holdings) Limited; (e) Energy XXI International Limited; (f) Energy XXI Malaysia Limited; and (g) Ping Petroleum Limited.

Petition Date means April 14, 2016.

Plan means the Second Amended Proposed Joint Chapter 11 Plan of Reorganization (as amended, modified, or supplemented from time to time).

Provisional Liquidator means John C. McKenna, as appointed by the Bermuda Court.

Reorganized Debtors means the Debtors after completing the series of internal reorganization transactions pursuant to which, among other things, EXXI Ltd transferred all of its remaining assets to Reorganized EGC.

Industry Terms

In addition, below is a list of terms that are common to our industry and used throughout this 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	NGLs	Natural gas liquids

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.

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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 NGLs.

Operating costs include direct and indirect expenses, including general and administrative expenses, incurred to manage, operate and maintain wells and related equipment and facilities.

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

Production costs are costs incurred to operate and maintain our wells and related equipment and facilities. For a complete definition of production costs, please refer to Rule 4-10(a)(20) of Regulation S-X as promulgated by the SEC.

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

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

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

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

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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.

v

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in 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:

• new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting;

• uncertainty of our ability to improve our operating structure, financial results and profitability following emergence from Chapter 11 and other risks and uncertainties related to our emergence from Chapter 11;

• our inability to maintain relationships with suppliers, customers, employees and other third parties following emergence from Chapter 11;

• 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 departure of our senior leaders on our employees, suppliers, regulators and business counterparties;

• the ability of the Company to hire a permanent Chief Executive Officer;

• any effects from the same person serving, on an interim basis, as both, the Chairman of the Board of Directors and Chief Executive Officer of the Company at the same time;

• our ability to comply with covenants under the Exit Facility (as defined below);

• changes in 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;

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

• our current or 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 become quoted on the OTC markets or other national securities exchange;

• 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”);

1

• 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 (see Item 1A, Risk Factors, under “Lower oil and gas prices and other factors may result in future ceiling test write-downs of our asset carrying values”) due to lower commodity prices using SEC methodology, under which, commodity prices are 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;

• future 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;

• we may be limited by financial/seasonal limits as required under our credit facility;

• our degree of success in replacing our oil and natural gas reserves through capital investment;

• 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.

2

EXPLANATORY NOTE REGARDING THIS TRANSITION REPORT

On February 7, 2017, the board of directors of the Company (the “Board”) adopted a resolution to change the Company’s fiscal year end from June 30 to December 31. As a result, this Form 10-K is a transition report and includes financial information for the transition period from July 1, 2016 through December 31, 2016. Subsequent to this report, our reports on Form 10-K will cover the calendar year, January 1 to December 31, which will be our fiscal year. Unless otherwise noted, all references to “years” in this Form 10-K refer to the twelve-month fiscal year, which prior to July 1, 2016 ended on June 30, and beginning after June 30, 2016 will end on December 31.

PART I

Item 1. Business

We are headquartered in Houston, Texas and have historically engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico Shelf, which is an area in less than 1,000 feet of water (“GoM Shelf”).

We have historically focused on development and extension drilling on our existing core properties to enhance production and ultimate recovery of reserves, supplemented by exploration and strategic acquisitions from time to time. Our acquisition strategy has historically been 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 have provided us with an inventory of low-risk recompletion and drilling opportunities in our geographic area of expertise.

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 records 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 by providing for a more efficient sweep mechanism that minimizes water coning versus a vertical well;

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

• utilizing reprocessed and Wide Azimuth 3D 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 sweep incremental oil.

The above techniques enable us to continually replenish our 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 may provide us with opportunities to place service work out to bid to obtain better services and prices.

At December 31, 2016, our total proved reserves were 121.9 MMBOE of which 81% were oil and 70% were classified as proved developed. We operated or had an interest in 616 gross producing wells on 439,294 net developed acres, including interests in 57 producing fields. We believe operating our assets is a key to our success and approximately 91% of our proved reserves are on properties operated by us. Our geographical concentration on the GoM Shelf enables us to manage the operated fields efficiently and our high number of wellbore locations provides diversification of our production and reserves.

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Emergence from Chapter 11

On the Petition Date, the Debtors filed voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11. As a result of filing of the Bankruptcy Petitions, EXXI Ltd’s common stock was delisted from the Nasdaq Global Select Market (“NASDAQ”).

On December 13, 2016, the Bankruptcy Court entered the Confirmation Order, which approved and confirmed the Plan as modified by the Confirmation Order.

On December 30, 2016, the Debtors satisfied the conditions to effectiveness of the Plan and the Plan became effective in accordance with its terms and the Reorganized Debtors emerged from Chapter 11. For more information regarding the Debtors’ emergence from the Chapter 11 Cases, please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Emergence from Chapter 11.”

In connection with the satisfaction of the conditions to effectiveness as set forth in the Confirmation Order and in the Plan, EXXI Ltd and EGC completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to Reorganized EGC, as the new parent entity; accordingly, Reorganized EGC succeeded to the business and operations previously consolidated for accounting purposes by EXXI Ltd.

Concurrently with the filing of the Bankruptcy Petitions, EXXI Ltd filed a petition seeking an order for liquidation of EXXI Ltd in the Bermuda Court. On April 15, 2016, John C. McKenna was appointed as Provisional Liquidator by the Bermuda Court. In light of the Plan and the emergence of EXXI Ltd from Chapter 11, the Bermuda Court granted the entry into a winding up order formally placing EXXI Ltd in liquidation and confirming John C. McKenna as Provisional Liquidator. The liquidation is expected to be completed during the first half of 2017, and EXXI Ltd will, at such conclusion, be dissolved. During the pendency of the Bermuda Proceeding, EXXI Ltd has adopted a modified reporting program with respect to its reporting obligations under federal securities laws. EXXI Ltd does not intend to file periodic reports while the Bermuda Proceeding is pending, but will continue to file current reports on Form 8-K as required by federal securities laws.

In accordance with the Plan, the following significant transactions occurred:

Prepetition Notes

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the prepetition notes, except the 4.14% promissory note, issued by EXXI Ltd, EGC and EPL and the related collateral agreements and registration rights, as applicable, were cancelled, and the indentures governing such obligations were cancelled. For more information, please read Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Plan of Reorganization —  Prepetition Notes.”

Prepetition Revolving Credit Facility and Exit Facility

On the Emergence Date, by operation of the Plan, all outstanding obligations under the Second Amended and Restated First Lien Credit Agreement (the “Prepetition Credit Agreement” or the “Prepetition Revolving Credit Facility”) and the related collateral agreement were cancelled and the credit agreements governing such obligations were cancelled.

Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three-year secured credit facility (the “Exit Facility”) with the majority of lenders under the Prepetition Credit Facility. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Prepetition Revolving Credit Facility of approximately $74 million and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides for the making of revolving loans and the issuance of letters of credit. On the Emergence Date, the aggregate commitments under the Exit Revolving Facility were approximately $227.8 million, all of which

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will be utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of ExxonMobil Corporation (“ExxonMobil”) to secure certain plugging and abandonment obligations related to assets in the Gulf of Mexico. On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with ExxonMobil, it was agreed that subsequent to the Predecessor Company’s emergence from the Chapter 11 proceedings, the letters of credit issued in favor ExxonMobil would be reduced to $200 million from the existing amount of $225 million and currently documents are being formalized to effect such reduction. As of December 31, 2016, there was no available borrowing capacity under our Exit Facility. A more detailed description of the Exit Facility is provided in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations —  Liquidity and Capital Resources — Exit Facility.”

Equity Interests

As a result of the Plan, there are no assets remaining in EXXI Ltd, and, under Bermuda law, shareholders (including preferred shareholders) of EXXI Ltd will receive no payments and all of its existing share-based compensation plans were also cancelled. EXXI Ltd will be dissolved at the conclusion of the Bermuda Proceeding, and as such, the shareholders will no longer have any interest in EXXI Ltd as a matter of Bermuda law.

On the Emergence Date, the Reorganized EGC issued 100% of its shares of common stock to certain of the Debtors’ creditors pursuant to the Plan. For more information, please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Plan of Reorganization — Equity Interests.”

Warrant Agreement

On the Emergence Date, the Reorganized EGC entered into a warrant agreement (the “Warrant Agreement”) with Continental Stock Transfer & Trust Company, as Warrant Agent. Pursuant to the terms of the Plan, Reorganized EGC issued 2,119,889 warrants to certain prepetition noteholders pursuant to the Plan. For more information, please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Plan of Reorganization — Warrant Agreement.”

Non-Continuing EXXI Ltd Directors

Pursuant to the Plan, as of the Emergence Date, the following directors resigned from EXXI Ltd’s board of directors: William Colvin, Cornelius Dupré II, Hill A. Feinberg, Kevin Flannery, Scott A. Griffiths and James LaChance. On January 3, 2017, John D. Schiller, Jr. also resigned as the remaining sole director of EXXI Ltd. Following the resignation of all of the directors of EXXI Ltd and in accordance with Bermuda law, the Provisional Liquidator assumed full control of EXXI Ltd’s affairs and will continue to do so until the liquidation of EXXI Ltd is complete.

Departure and Appointment of Company Directors

Upon the effectiveness of the Plan, Bruce W. Busmire resigned as director of EGC. On the Emergence Date, by operation of the Plan, Michael S. Bahorich, George Kollitides, Steven Pully, Michael S. Reddin, James “Jay” W. Swent III and Charles W. Wampler joined John D. Schiller, Jr., an existing director of EGC, were appointed as members of the Board.

On February 2, 2017, John D. Schiller, Jr. resigned from his position as President and Chief Executive Officer (“CEO”) of the Company and also ceased to serve as a member of the Board. As a result, on February 2, 2017, the Board appointed Michael S. Reddin, the Company’s Chairman of the Board, to serve as the Company’s President and CEO on an interim basis. Mr. Reddin will continue to serve as Chairman of the Board. Because Mr. Reddin is now serving as both as Chairman of the Board and CEO, the Board has amended and restated the Company’s bylaws to provide for a Lead Independent Director and has appointed director James “Jay” W. Swent III to serve in that capacity. In order to eliminate the Board vacancy created by Mr. Schiller’s departure from the Board, the size of the Board was reduced from seven to six on February 2, 2017.

For more information, please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance.”

5

Departure and Appointment of Company Officers and Long Term Incentive Plan

In accordance with the Plan, prior to the Emergence Date, the following officers of EXXI Ltd were appointed as officers of the Company: John D. Schiller, Jr. — Chief Executive Officer and President, Bruce W. Busmire — Chief Financial Officer, Antonio de Pinho — Chief Operating Officer and Hugh Menown —  Executive Vice President, Chief Accounting Officer. On February 2, 2017, Mr. Schiller, Mr. Busmire and Mr. de Pinho resigned as President and CEO, Chief Financial Officer and Chief Operating Officer, respectively. As a result, on February 2, 2017, the Board appointed (i) Scott M. Heck to join the Company as the Company’s new Chief Operating Officer (“COO”) to succeed Mr. de Pinho and (ii) Hugh A. Menown, the Company’s current Executive Vice President and Chief Accounting Officer, as the Company’s Chief Financial Officer (“CFO”) on an interim basis to succeed Mr. Busmire.

As of the Emergence Date, the Company also entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the go-forward compensation for the Reorganized Debtors’ officers, directors, employees and consultants and an employment agreement with our former President and CEO, John D. Schiller, Jr. In connection with his termination of employment, the employment-related provisions of his Employment Agreement, dated as of December 30, 2016, with the Company (the “Schiller Employment Agreement”) were terminated as of February 2, 2017. Under the Schiller Employment Agreement, Mr. Schiller is entitled to receive the following benefits, subject to his entry into a waiver and release agreement (i) a lump-sum cash severance payment in the amount of $2 million, and (ii) reimbursement for the monthly cost of maintaining health benefits for Mr. Schiller and his spouse and eligible dependents as of the date of his termination for a period of 18 months to the extent Mr. Schiller elects COBRA continuation coverage, less applicable taxes and withholding. The $2 million cash severance payment is payable on April 3, 2017, the 60^th day after the termination date. On February 2, 2017, the Company entered into a consulting agreement (the “Schiller Consulting Agreement”) with Mr. Schiller, pursuant to which Mr. Schiller has agreed to serve as a special advisor to the Board during a transition period of up to six months. In consideration for those services, the Company has agreed to pay Mr. Schiller a consulting fee equal to $50,000 per month.

Additionally, the Company entered into employment agreements with Scott M. Heck and Michael S. Reddin as our COO and Interim President and CEO, respectively. For more information, please read Part III, Item 11. “Executive Compensation — Long Term Incentives” and Part III, Item 11. “Executive Compensation — Potential Payments upon Termination or a Change in Control.”

For more information, please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance.”

Fresh Start Accounting

Upon emergence from the Chapter 11 Cases, the Company adopted fresh start accounting in accordance with the provisions set forth in ASC 852. For more information regarding the Plan, please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Emergence from Chapter 11 Proceedings — Fresh Start Accounting.”

While the emergence from bankruptcy is effectively complete, certain administrative activities will continue under the authority of the Bankruptcy Court for the next several months. For more information regarding the Plan, please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Plan of Reorganization.”

Business Strategy and Strengths

We have historically focused on developing high quality oil-producing assets with relatively low production decline rates. To effectively execute our business strategy, we have assembled a team of engineers with an average of 20 years of industry experience and a team of geologic and geophysical experts with an average of 34 years of industry experience. Our technical staff has specific expertise in developing our core properties. Additionally, the members of our senior management team average 32 years of operating experience on the GoM Shelf.

Due to significant technological advancements in drilling and completion techniques for oil reserves, we believe our high percentage of oil reserves compared to our overall reserve base provides us with an economic

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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 91% 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.

Our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with being a company newly emerged from Chapter 11 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 December 31, 2016. These properties represent our core properties and are ranked based on PV-10 (as defined below) of proved reserves as of December 31, 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 389 MMBOE. There are seven production platforms and 38 active wells located throughout the field. The field’s net production for the month of December 2016 of 3.7 MBOE/Day (“MBOED”) accounted for approximately 9% of our net production. Net proved reserves for the field, which is our largest field based upon net proved reserves, were 93% oil at December 31, 2016.

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 152 MMBOE. There are six production platforms and 28 active wells located throughout the field. The field’s net production for the month of December 2016 of 2.5 MBOED accounted for approximately 6% of our net production. Net proved reserves for the field were 74% oil at December 31, 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 acquisition of EPL for approximately $2,500 million, including the assumption of debt (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 13 active wells located throughout the field. Production is processed through one central production platform, and the field has produced in excess of 111 MMBOE. The field’s net production for the month of December 2016 of 1.7 MBOED accounted for approximately 4% of our net production. Net proved reserves for the field were 60% oil at December 31, 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. The field consists of federal OCS blocks Main Pass 60, 61, 62 and 63. Initially discovered by Pogo Producing Company in 2000, the field has produced in excess of 65 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 reservoirs deposited in an outer shelf/upper slope channel/levee/overbank complex deposited on the regional south dip. The two larger J-6 Sand reservoirs, pods A and B are oil reservoirs that are being waterflooded to maintain reservoir pressure and

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maximize recovery. There are 28 producing wells and three major production platforms located throughout the field. The field’s net production for the month of December 2016 of 3.9 MBOED accounted for approximately 9% of our net production. Net proved reserves for the field were 86% oil at December 31, 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 and Lower Pliocene reservoir. The field was discovered by Pure Energy in 1960 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 December 2016 of 2.7 MBOED accounted for approximately 6% of our net production. Net proved reserves for the field were 85% oil at December 31, 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 associated with 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 751 MMBOE. There are 45 production structures and 82 active wells located throughout the field. The field’s net production for the month of December 2016 of 4.0 MBOED accounted for approximately 9% of our net production. Net proved reserves for the field were 90% oil at December 31, 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 29 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 264 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 December 2016 of 4.8 MBOED accounted for approximately 10% of our net production. Net proved reserves for the field were 50% oil at December 31, 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, 29 smaller structures and 46 active wells located throughout the fields. The area’s net production for the month of December 2016 of 2.2 MBOED accounted for approximately 5% of our net production. Net proved reserves for the field were 79% oil at December 31, 2016. This field is the tenth largest oil field on the GoM Shelf.

8

Reserve Estimation Procedures and Internal Controls over Reserve Estimates

For the six month transitional period ended December 31, 2016, proved reserves were estimated and compiled for reporting purposes by our internal reservoir engineers. 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:

• The Audit Committee is apprised of the processes and the estimates used in compiling of proved reserves;

• Prior to issuance of the final internal reserves report, the Board meets with Director of Reserves or his designee to review material changes, if any, 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, which is a master file maintained by our land department to ensure the accuracy of number of wells, platforms, pipelines and other assets owned by the Company, as well as track the Company’s ownership in such assets;

• Proved undeveloped property drilling (and/or development) schedules are reviewed and approved by the Audit Committee and certain members of senior management;

• Senior management regularly reviews our drilling schedule, if any, 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. This information is considered prior to approval of the current fiscal-year development schedule and associated reserves estimates;

• Material reserve changes are reviewed and approved by the Director of Reserves, or his designee, 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

Our Director of Reserves, Lee I. Williams, is the technical person primarily responsible for overseeing the preparation of our internal reserves estimates. He has 16 years of industry experience with positions of increasing responsibility and has over 13 years of 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.

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

9

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.

Summary of Oil and Gas Reserves at December 31, 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. 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. Please read Item 1A. Risk Factors “— Our actual recovery of reserves may differ from our proved reserve estimates.” and “— Our estimates of proved reserves have not been prepared or audited by an independent reserve firm and, as a result, may vary considerably from an independent reserve estimate.”

	Successor
	Summary of Oil and Natural Gas Reserves as of December 31, 2016 Based on Average Twelve Month Period Prices
	Oil MMBbls		NGLs MMBbls		Natural Gas Bcf		MMBOE		Percent of Total Proved			PV-10 (in thousands)(1)(2)(3)
Proved
Developed		63.7		2.7		113.6		85.4		70	%	$	(180,423	)
Undeveloped		31.5		0.4		27.6		36.5		30	%		315,833
Total proved		95.2		3.1		141.2		121.9					135,410
Future income taxes													—
Less present value discount at 10%													—
Future income taxes discounted at 10%													—
Standardized measure of future discounted net cash flows												$	135,410

(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 ended on December 31, 2016) used in determining future net revenues were $42.74 per barrel of oil for West Texas Intermediate (“WTI”) benchmark less $1.23 per barrel for crude quality and location differentials, for a total of $41.51 per barrel. For NGL’s, the average price used was $21.63 per barrel. For natural gas, the average price used was $2.48 per MMBtu for Henry Hub benchmark less $0.19 per MMBtu for gas quality and location differentials, for a total of $2.29 per MMBtu.

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(2) We recorded no future income taxes primarily due to our inability to currently record any additional deferred tax assets. Further, the elimination of our U.S. federal income tax net operating loss (“NOL”) carryforwards and the reduction in tax basis of our properties upon emergence from Chapter 11 may subject us to cash income taxes after the Convenience Date, which may have an impact on our standardized measure of discounted future net cash flows.

(3) The negative value for proved developed reserves results from discounted plugging and abandonment costs exceeding the discounted cash flows from the developed reserves. This is due to allocating all of the plugging and abandonment costs to the proved developed reserves. The development of the proved undeveloped reserves is expected to generate positive cash flow for the total proved reserves.

Changes in Proved Reserves

Our proved reserves increased by 35.4 MMBOE or by approximately 41% from 86.6 MMBOE at June 30, 2016 to 121.9 MMBOE as of December 31, 2016. The increase was primarily due to:

• The booking of 36.5 MMBOE of proved undeveloped reserves. These reserves had been previously recorded by EXXI Ltd and then subsequently removed by it in the December 31, 2015 quarter due to the uncertainty regarding its ability to secure the required financing for developing such reserves prior to the Chapter 11 Cases; and

• Upward revisions of approximately 6.4 MMBOE of proved reserves resulting primarily from the extension in field life due to the addition of proved undeveloped reserves.

These were offset by:

• 7.9 MMBOE of production during the period.

Development of Proved Undeveloped Reserves

Due to the depressed commodity prices and EXXI Ltd’s lack of capital resources to develop its properties, the proved undeveloped oil and natural gas reserves no longer qualified as being proved as of December 31, 2015. As a result, EXXI Ltd removed all of our proved undeveloped oil and natural 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 were still economic at prices and costs applicable to SEC reserve reports at such date, 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 then current constraints on EXXI Ltd’s ability to fund development drilling.

Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million.

We update and approve our reserves development plan on an annual basis (updated at an interval of six months as of December 31, 2016), which includes our program to drill proved undeveloped locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value, cash flow and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total proved undeveloped reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors; including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves. As scheduled in our long range plan, substantially all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report.

Our current proved undeveloped schedule is also subject to change due to external factors such as changes in commodity prices, the availability of capital, acquisitions, regulatory matters and the availability of drilling rigs that are capable of drilling in a given area. Senior management continuously monitors our development drilling plan to ensure that there is reasonable certainty of proceeding with our development plans and is required to approve any changes made to the existing long range plan and the related development plan. The following table presents the percentage of proved undeveloped reserves scheduled to be developed by fiscal year, in accordance with our long range plan.

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	Successor
Year Ending December 31,	Percentage of Proved Undeveloped Reserves Scheduled to be Developed
2017		4.2	%
2018		26.7	%
2019		26.2	%
2020		22.2	%
2021		20.2	%
2022 – 2029		0.5	%
Total		100.0	%

Drilling Activity

The following table sets forth our drilling activity.

	Predecessor
	Six Months Ended December 31, 2016				Year Ended June 30,
					2016				2015				2014
	Gross		Net		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 December 31, 2016, we had no wells being drilled.

Delivery Commitments

We had no delivery commitments in the six month transition period ended December 31, 2016.

Productive Wells

Our working interests in productive wells were as follows:

	Successor				Predecessor
	December 31,				June 30,
	2016				2016				2015
	Gross		Net		Gross		Net		Gross		Net
Natural gas		100		73		103		76		86		65
Crude oil		516		425		532		436		481		438
Total		616		498		635		512		567		503

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Acreage

Working interests in developed and undeveloped acreage were as follows:

	Successor
	December 31, 2016
	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Onshore		11,529		2,904		64,351		28,591		75,880		31,495
Offshore		537,888		436,390		204,349		114,617		742,237		551,007
Total		549,417		439,294		268,700		143,208		818,117		582,502

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

	Successor
	Year Ended December 31,
	2017				2018				2019
	Gross		Net		Gross		Net		Gross		Net
Onshore		8,272		3,496		2,546		725		861		605
Offshore		57,854		30,771		30,186		11,771		49,556		40,618
Total		66,126		34,267		32,732		12,496		50,417		41,223

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 were as follows:

	Predecessor
	Six Months Ended December 31,		Year Ended June 30,
	2016		2016		2015		2014
	(in thousands)
Property acquisitions
Proved	$	1,500	$	26,400	$	—	$	2,046,879
Unevaluated		—		—		2,304		924,882
Exploration costs		—		1,400		38,183		153,136
Development cost		22,300		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.”

	Predecessor
	Six Months Ended December 31,			Year Ended June 30,
	2016			2016			2015			2014
Sales Volumes per Day
Natural gas (MMcf)		73.3			92.8			102.7			89.7
NGLs (MBbls)		0.9			2.5			2.7			2.4
Crude oil (MBbls)		29.8			34.5			39.1			27.7
Total (MBOE)		42.9			52.5			58.9			45.0
Percent of BOE from crude oil and NGLs		72	%		71	%		71	%		67%

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	Predecessor
	Six Months Ended December 31,		Year Ended June 30,
	2016		2016		2015		2014
Average Sales Price
Natural gas per Mcf	$	2.75	$	2.04	$	3.13	$	4.15
NGLs per Bbl	$	21.12	$	16.09	$	28.09	$	40.78
Crude oil per Bbl	$	46.52	$	42.13	$	71.82	$	105.86
Sales price per BOE	$	37.44	$	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 December 31, 2016. Our average daily production, average sales prices and production costs for that field are as follows:

	Predecessor
	Six Months Ended December 31,			Year Ended June 30,
	2016			2016			2015			2014
West Delta 73
Sales Volumes per Day
Natural gas (MMcf)		1.8			3.0			4.3			7.5
NGLs (MBbls)		—			0.1			0.1			0.1
Crude oil (MBbls)		3.8			4.8			4.9			4.1
Total (MBOE)		4.1			5.4			5.8			5.5
Percent of BOE from crude oil and NGLs		93	%		91	%		86	%		75	%
Average Sales Price
Natural gas per Mcf	$	4.31		$	2.34		$	3.46		$	4.22
NGLs per Bbl	$	—		$	14.72		$	25.18		$	40.74
Crude oil per Bbl	$	46.01		$	42.91		$	68.63		$	105.06
Production cost per BOE	$	15.90		$	16.99		$	19.91		$	19.76

Production Unit Costs

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

	Predecessor
	Six Months Ended December 31,		Year Ended June 30,
	2016		2016		2015		2014
Average Cost per BOE
Production costs
Lease operating expense
Insurance expense	$	1.60	$	1.98	$	1.86	$	1.90
Workover and maintenance		2.88		3.03		3.05		4.04
Direct lease operating expense		13.72		13.01		16.64		16.31
Total lease operating expense		18.20		18.02		21.55		22.25
Production taxes		0.06		0.08		0.39		0.33
Total production costs	$	18.26	$	18.10	$	21.94	$	22.58
Gathering and transportation	$	2.48	$	2.91	$	0.98	$	1.43
Depreciation, depletion and amortization rates	$	7.68	$	17.67	$	32.81	$	25.19

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Derivative Activities

We have historically engaged in a hedging program designed to manage our commodity price risk and enhance cash flow certainty and predictability. The Company did not enter into any derivative instruments during the six month transition period ended December 31, 2016, accordingly, at December 31, 2016, we had no outstanding derivative contracts. In February 2017, we entered into oil contracts (costless collars) benchmarked to Argus-LLS, to hedge 10,000 barrels per day (“BPD”) of our production for the period from March 2017 to December 2017 with an average floor price of $52.30 and an average ceiling price of $57.43. 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 natural 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”), Chevron USA (“Chevron”) and Shell Trading Company (“Shell”) accounted for approximately 27%, 26%, and 26%, respectively, of our total oil and natural gas revenues during the six month transition period ended December 31, 2016. Trafigura accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2016. Chevron accounted for approximately 22% and 24% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015, respectively. 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 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 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. Please read Item 1A. “Risk Factors — 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 and “— We recently emerged from bankruptcy, which could adversely affect our business and relationships.”

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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, NGLs 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 different than other natural gas producers in our areas of operation.

The price we receive from the sale of oil, natural gas and NGLs is affected by the cost of transporting those products to market. Rates charged and terms of service for the interstate pipeline transportation of oil, NGLs 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, natural gas and NGLs.

Market manipulation and market transparency regulations.  Under the Energy Policy Act of 2005 (“EPAct 2005”), FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity” in order to enforce the anti-market manipulation provisions

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in the EPAct 2005. The Commodity Futures Trading Commission (“CFTC”) also holds authority to regulate certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. Likewise, the Federal Trade Commission (“FTC”) holds authority to regulate wholesale petroleum markets pursuant to the Federal Trade Commission Act and the Energy Independence and Security Act of 2007. With regard to our physical purchases and sales of natural gas, NGLs 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, NGLs and refined petroleum products pipelines, be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Under the ICA, shippers may challenge new or existing rates or services. FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. A successful rate challenge could result in an oil pipeline paying refunds for the period that the rate was in effect and/or reparations for up to two years prior to the filing of a complaint. FERC generally has not investigated oil pipeline rates on its own initiative.

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

The EPAct of 1992 further required FERC to establish a simplified and generally applicable ratemaking methodology for interstate oil pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows oil pipelines to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, plus 2.65 percent. Rate increases made under the index are subject to protest, but the scope of the protest proceeding is limited to an inquiry into whether the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. The indexing methodology is applicable to any existing rate, including a grandfathered rate.

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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. In particular, 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. In July 2016, the agency issued a new NTL that went into effect on September 12, 2016 (the “September 2016 NTL”) and augments requirements for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to satisfy decommissioning obligations on the OCS. Only recently, on January 6, 2017, the BOEM announced that it was extending the implementation timeline for providing financial assurance under the September 2016 NTL by an additional six months (the “January 2017 Extension”). This January 2017 Extension of time is not program-wide but, rather, only applicable to leases, rights-of-way and rights of use and easement for which there are co-lessees and/or predecessors in interest. Operators of so-called “sole liability properties” — leases, rights-of-way and rights of use and easement for which the holder is the only liable party — must continue to adhere to financial assurance timelines as imposed by the BOEM pursuant to the September 2016 NTL.

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

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gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner differently than other companies in our areas of operation.

Environmental Regulations

Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the handling, discharge and disposition of waste materials, the reclamation and abandonment of wells, sites and facilities, the establishment of financial assurance requirements for oil spill response costs and the decommissioning of offshore facilities and the remediation of contamination resulting from our operations. These laws and regulations may impose liabilities for noncompliance and contamination arising from our operations and may result in the assessment of sanctions, including administrative, civil and criminal penalties, or require suspension or cessation of operations in affected areas.

The environmental laws and regulations, as amended from time to time, applicable to us and our operations include, among others, the following United States federal laws and regulations:

• Clean Air Act, which governs the emission of air pollutants from many sources, imposes various pre-construction, monitoring and reporting requirements, and is relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;

• Clean Water Act, which governs discharges of pollutants from facilities 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 (the “RCRA”), 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 implementing a safety hazardous communication program and reporting of toxic chemical used in inventories; and

• Safe Drinking Water Act, which ensures the quality of public drinking water and 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

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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 trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or the re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal or remediation requirements, could have a material adverse effect on the Company’s financial position and the drilling program’s results of operations. For example, during October 2015, the EPA issued a final rule lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017. In a second example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the costs to manage and dispose of wastes generated from exploration and production activities. On an international level, in December 2015, the United States joined the international community at the 21^st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. 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 regulatory initiatives, or any other future laws, rules or initiatives, 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

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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.  At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the federal Clean Air Act that, among other things, establish certain permits and construction reviews designed to allow operations while ensuring the Prevention of Significant Deterioration (as defined in the federal Clean Air Act) of air quality by GHG emissions from large stationary sources that are already potential sources of significant, or criteria, pollutant emissions. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including onshore and offshore oil and gas production facilities. Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations; in June 2016, the EPA published new source performance standards that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and volatile organic compound emissions.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and a number of states or groupings of states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG 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 GHGs. The adoption of legislation or regulatory programs to reduce emissions of GHGs 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 GHGs 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 GHGs 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 237 employees at December 31, 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 Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents we file with the SEC at www.sec.gov.

Our web site address is www.energyxxi.com. We make available, free of charge on or through our web site, our Annual Reports on Form 10-K, proxy statements, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or accessible through, our website is not incorporated by reference into this Form 10-K.

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Item 1A. Risk Factors

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 Cases could adversely affect our business and relationships with customers, employees and suppliers. Due to uncertainties, many risks exist, including the following:

• key suppliers could terminate their relationship or require financial assurances or enhanced performance;

• the ability to renew existing contracts and compete for new business may be adversely affected;

• the ability to attract, motivate and/or retain key executives and employees may be adversely affected;

• employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and

• competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy will not be comparable to our historical financial information as a result of the implementation of the plan of reorganization and the transactions contemplated thereby and our adoption of fresh start accounting.

In connection with the Disclosure Statement we filed with the Bankruptcy Court for the Confirmation Hearing, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we adopted fresh start accounting. Accordingly, our future financial conditions and results of operations will not be comparable to the financial condition or results of operations reflected in the Predecessor’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

There is a limited trading market for our securities and the market price of our securities is subject to volatility.

Following our emergence from bankruptcy, our common stock began limited trading as reported as “grey market” trades by OTC Markets. We expect our common stock to be quoted on OTC Pink marketplace, and we intend to pursue a listing on the NASDAQ in the near term. However, no assurances can be given regarding the Company’s ability to do so in a timely manner or at all. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of market makers in our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated

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variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Form 10-K. No assurance can be given that an active market will develop for our common stock or as to the liquidity of the trading market for our common stock. Our common stock may be traded only infrequently, and reliable market quotations may not be available. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.

Since the emergence from bankruptcy, the composition of our Board of Directors changed completely.

The composition of the Board has changed significantly. Currently, the Board is made up of six directors, and none of the new directors have previously served on the Board of the Predecessor Company. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the direction of the Company and other issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. We may not be able to replace our interim CEO, interim CFO or other key personnel in the event of resignation, retirement or termination in a timely manner, and we could experience significant declines in productivity.

We do not expect to pay dividends in the foreseeable future.

We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, restrictive covenants in certain debt instruments to which we are or may be a party, may limit our ability to pay dividends, any of which may negatively impact the trading price of our common stock.

Certain provisions of our certificate of incorporation and our bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our certificate of incorporation and our bylaws may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our certificate of incorporation and bylaws include, among other things, those that:

• authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;

• establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and

• limit the persons who may call special meetings of stockholders.

While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any

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attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Circumstances may arise in which our significant stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common stock because investors may perceive disadvantages in owning shares in companies with significant stockholders.

Future sales of our common stock in the public market or the issuance of securities senior to our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and our ability to raise funds in stock offerings.

A large percentage of our shares of common stock are held by a relatively small number of investors. Further, we entered into a registration rights agreement with certain of those investors pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales by our stockholders of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities. For more information, please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Plan of Reorganization — Equity Interests.”

We are currently authorized to issue 100 million shares of common stock and 10 million shares of preferred stock of the Company with such designations, rights, preferences, privileges and restrictions as determined by the Board. As of December 31, 2016, we had outstanding approximately 33.2 million shares of common stock of the Company and 2.1 million warrants to purchase an aggregate of 2.1 million shares of common stock of the Company at an initial exercise price of $43.66 per share of common stock. We have also reserved approximately 1.9 million shares of common stock of the Company for future issuance to our directors, officers and employees as restricted stock, stock option or any other stock based compensation awards pursuant to our 2016 LTIP. The potential issuance of such additional shares of common stock may create downward pressure on the future trading price of our common stock.

We may issue common stock or other equity securities senior to our common stock in the future for a number of reasons, including to finance acquisitions, to adjust our leverage ratio and to satisfy our obligations upon the exercise of warrants, other equity securities or for other reasons. We cannot predict the effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or the availability of shares of common stock or such other equity securities for future sale or issuance, will have on the trading price of our common stock.

The warrants issued by the Company in accordance with the Plan may be exercised for shares of common stock of the Company, which could have a dilutive effect to stockholders of the Company.

In accordance with the terms of the Plan, on the Emergence Date, we issued warrants initially exercisable for one share of common stock of the Company per warrant at an initial exercise price of $43.66. The warrants are exercisable in whole or in part. The exercise of these warrants into common stock of the Company could have a dilutive effect to the holdings of our stockholders of the Company.

There is no assurance that the market price of our common stock will ever exceed the exercise price of the warrants, and as a result, the warrants may expire worthless. Further, the terms of such warrants may be amended in a manner adverse to warrant holders.

The market price of our common stock is extremely speculative and volatile. There is no assurance that the market price of our common stock will exceed the warrant exercise price, currently $43.66 per share, under the warrants issued by the Company on the Emergence Date in accordance with the Plan before

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December 30, 2021, the expiration date of the warrants, and they may expire worthless. In addition, the Warrant Agreement provides that the terms of the warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least a certain percentage of the then outstanding warrants originally issued to make any change that adversely affects the interests of the registered holders. Accordingly, we may amend the terms of the warrants in a manner adverse to a holder if holders of at least a certain percentage of the then outstanding warrants approve of such amendment.

The Exit Facility and our 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, our Predecessor depended on the Prepetition Revolving Credit Facility for a portion of its capital needs. On the Emergence Date, by operation of the Plan, all outstanding obligations under Prepetition Revolving Credit Facility, the related collateral agreement and the credit agreements governing such obligations were cancelled.

Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into the Exit Facility, which is comprised of two facilities: (i) an Exit Term Loan facility resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Debtors’ Prepetition Revolving Credit Facility of approximately $74 million and (ii) the Exit Revolving Facility resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides for the making of revolving loans and the issuance of letters of credit. On the Emergence Date, the aggregate commitments under the Exit Revolving Facility were approximately $227.8 million, all of which was utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of ExxonMobil to secure certain plugging and abandonment obligations.

As of the Emergence Date, the Company met the requirement under the Exit Facility to have liquidity of at least $90 million. (the “Minimum Cash Balance”). However, we may not be able to access adequate funding in the future as there was no remaining available borrowing capacity contemplated under the Exit Facility as of the Emergence Date, 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.

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

Under the Internal Revenue Code of 1986, as amended (the “Tax Code”), a debtor that realizes cancellation of indebtedness income (“CODI”) pursuant to a Bankruptcy Court approved plan of reorganization may exclude this income from taxation in the year/period of the discharge. However, the tax attributes of such a debtor are reduced to the extent that CODI is excluded from gross income pursuant to the Chapter 11 Cases (the “Tax Attribute Reduction Rules”). As a result, the CODI recognized for tax purposes upon the Predecessor’s emergence from Chapter 11 and all of its consolidated NOL carryforwards have been eliminated and other tax attributes (principally, the tax bases of our oil and natural gas properties subject to future recovery against taxable income via tax depreciation, depletion and amortization) have been substantially reduced under the Tax Attribute Reduction Rules. As a result, depending on future operations and drilling activity, the Company may be subject to paying cash income taxes in periods after emergence from the Chapter 11 Cases.

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

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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. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves may be impaired if cash flow from operations remains limited and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to 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 2015 with continued lower prices into 2016. The WTI crude oil price per barrel for the period from October 1, 2014 to December 31, 2016 ranged from a high of $91.01 to a low of $26.21, a decrease of 71.2%, and the New York Mercantile Exchange (“NYMEX”) natural gas price per MMBtu for the period October 1, 2014 to December 31, 2016 ranged from a high of $4.49 to a low of $1.64, a decrease of 63.5%. As of December 31, 2016, the spot market price for WTI was $53.72. 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. 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 believe we have provided the BOEM with all bonds or other surety in order to currently maintain compliance with BOEM regulations, although additional bonds could be required which may be costly and could potentially have negative impact on operating cash flows.

To ensure that the various obligations of lessees on the OCS, such as the cost to plug and abandon wells, decommission and remove platforms and pipelines, and to clear the seafloor of obstructions at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable financial

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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. In July 2016, the agency issued its September 2016 NTL that revised requirements for the posting of additional security to satisfy decommissioning obligations. Additionally, the September 2016 NTL eliminated the exemption from the posting of financial assurances. On January 6, 2017, the BOEM announced its January 2017 Extension. This January 2017 Extension of time is not program-wide but, rather, only applicable to leases, rights-of-way and rights of use and easement for which there are co-lessees and/or predecessors in interest. Operators of “sole liability properties” — leases, rights-of-way and rights of use and easement for which the holder is the only liable party — must continue to adhere to financial assurance timelines as imposed by the BOEM pursuant to the September 2016 NTL.

We are a lessee and operator of oil and natural gas leases on the OCS and consequently, as of December 31, 2016, we have submitted, approximately $226.7 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.

The future cost of compliance with our existing supplemental bonding requirements, including such bonding obligations as reflected in the long-term financial assurance plan (“Long-Term Plan”) approved and executed by the BOEM on February 25, 2016, as such plan may be revised by the amended and supplemental plan submitted to the BOEM on June 28, 2016 (the “Proposed Plan Amendment”), 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 and the BOEM have executed the Long-Term Plan, we have since submitted the Proposed Plan Amendment for the agency’s consideration and approval that would revise the Long-Term Plan. We can provide no assurance that we can continue in the future 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 BSEE or the BOEM may have any of our operations on federal leases 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. For more information about the BOEM’s supplement bonding requirements, see “— Known Trends and Uncertainties — BOEM Supplemental Financial Assurance and/or Bonding Requirements.”

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

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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 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 trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or the re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal or remediation requirements, could have a material adverse effect on the partnership’s financial position and the drilling program’s results of operations. For example, during October 2015, the EPA issued a final rule lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017. In a second example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the costs to manage and dispose of wastes generated from exploration and production activities. 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 regulatory initiatives, or any other future laws, rules or initiatives, 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.

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 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

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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 capitalized costs 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 our oil and natural gas properties to the amount of the discounted cash flows.

Further declines in oil prices may adversely affect our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4-10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12-month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting.

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 average 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

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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 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.

Our estimates of proved reserves have not been prepared or audited by an independent reserve firm and, as a result, may vary considerably from an independent reserve estimate.

Estimates of proved oil and natural gas reserves are inherently uncertain, and any material inaccuracies in our reserve estimates will materially affect the quantities and values of our reserves. The estimates of our proved reserves as of December 31, 2016 included in this Form 10-K were prepared by our internal reserve engineers and professionals. Our internal estimates of proved reserves may vary considerably from independent proved reserve estimates prepared by an independent reserve engineering firm. Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material.

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 December 31, 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. 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.

Delays in the development of our reserves or increases in costs to drill and develop such reserves reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. Please read “Business — Development of Proved Undeveloped Reserves.”

As of December 31, 2016, approximately 20% 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 estimated, 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 reserve replacement needs from new prospects may be greater than those of other oil and gas

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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 operating 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.

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;

• 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;

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• 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 believe we have provided the BOEM with all bonds or other surety in order to currently maintain compliance with BOEM regulations, although additional bonds could be required which may be costly and could potentially have 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 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

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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 for 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 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

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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 66,126 gross acres (34,267 net) that could potentially expire during fiscal year 2017. We have limited capital to develop leases not currently held by production, or to re-lease or replace expiring leases.

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.

We operated approximately 91% of our proved reserves at December 31, 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 and others could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

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

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. From time to time, the availability of credit is more restrictive. Additionally, many of our vendors’, customers’ and counterparties’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or

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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 27%, 26% and 26%, respectively, of our total oil and natural gas revenues during the six month transition period ended December 31, 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. Our CEO, Chief Financial Officer and Chief Operating Officer recently departed and we have appointed a new interim Chief Executive Officer, interim Chief Financial Officer and COO. Transition between these roles could cause disruptions in our business.

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.

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 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;

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• 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 three 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.

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 the potential acquisition 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.

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We may be unable to successfully integrate the operations of the properties or businesses we acquire.

Integration of the operations of the properties we acquire with our existing business is a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:

• operating a larger organization;

• coordinating geographically disparate organizations, systems and facilities;

• integrating corporate, technological and administrative functions;

• diverting management’s attention from other business concerns;

• diverting financial resources away from existing operations;

• increasing our indebtedness; and

• incurring potential environmental or regulatory liabilities and title problems.

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

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 any 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.

Additional offshore drilling laws, regulations and other restrictions, delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans, and other related developments in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

In recent years, BSEE and BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these added and more stringent regulatory requirements and with existing environmental and oil spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill-response, and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and 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. For example, in April 2016, BSEE published a final rule on well control that, 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. Also, in April 2016, BOEM published a proposed rule that would update existing air emissions requirements relating to offshore oil and natural gas activity on the OCS. The BOEM regulates these air emissions in connection with its review of exploration and development plans, and right-of-way and rights of use and easement applications. The proposed rule would bolster existing air emission requirement by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to

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affect human health and public welfare that, depending on the results obtained, could result in subsequent rulemakings that restrict offshore air emissions. The BOEM also issued the September 2016 NTL that imposes more stringent requirements relating to the provision of financial assurance to satisfy decommissioning obligations. 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 material spill incidents were to occur in the future, the United States or other countries where such an event were to occur could elect 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, any of which developments could have a material adverse effect on our business. 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 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.

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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, natural gas and NGLs 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 NGLs.

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

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

State regulation of gathering facilities includes safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations may also be subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. State and local regulation may cause us to incur additional costs or limit our operations and can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.

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 or other approval before drilling or another regulated activity commences;

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• 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, remedial of corrective action obligations;

• the occurrence of delays in permitting or performance or expansion of projects; and

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

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 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

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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 GHGs could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the federal Clean Air Act that, among other things, establish certain permits and construction reviews designed to allow operations while ensuring the Prevention of Significant Deterioration of air quality by GHG emissions from large stationary sources that are already potential sources of significant, or criteria, pollutant emissions. To the extent that we become subject to these permitting requirements, we could be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs as well as criteria pollutants from such sources. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including onshore and offshore oil and gas production facilities. Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations; in June 2016, the EPA published new source performance standards that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. Additionally, in December 2015, the United States joined the international community at the 21^st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions.

The adoption and implementation of any international, federal or state legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax, which developments could have an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase

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the cost to the consumer, and thereby reduce demand for the oil and natural gas we produce. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our 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, NGLs and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, NGLs 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 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.

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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.

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

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage

43

depletion allowance for oil and 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. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s 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. 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.

SEC Proof of Claim

On June 17, 2016, the SEC filed a proof of claim against EXXI Ltd asserting a general unsecured claim in the amount of $3.9 million based on alleged violations of the federal securities laws by EXXI Ltd pertaining to the failure to disclose certain funds borrowed by our former President and CEO John D. Schiller, Jr. from personal acquaintances or their affiliates, certain of whom provided EXXI Ltd and certain of its subsidiaries with services and Mr. Schiller’s pledge of EXXI Ltd stock to a certain financial institution in the second half of 2014. The claim against EXXI Ltd has been classified as a general unsecured claim subject to a cap of approximately $1.4 million, which will be paid by EGC, under the Plan and will be subject to discharge, settlement and release in connection with the Chapter 11 Cases, and will 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.

44

PART II

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

Market Information for Common Stock

Prior to emergence from the Chapter 11 Cases, the common stock of EXXI Ltd, our predecessor, was listed on NASDAQ under the symbol “EXXI.” As a result of filing of the Bankruptcy Petitions, EXXI Ltd’s common stock was suspended from trading on the NASDAQ on April 25, 2016 and was formally delisted on May 19, 2016. From April 25, 2016 through emergence from the Chapter 11 Cases on December 30, 2016, trading in EXXI Ltd’s common stock was reported on the OTC Markets Group Inc.’s Pink Open Market (the “OTC Pink”) under the symbol “EXXIQ.” On December 30, 2016, upon emergence from the Chapter 11 Cases, EXXI Ltd’s common shares were removed from the OTC Market.

On January 10, 2017, trading in the Company’s common stock began being reported as “grey market” trades by OTC Markets Group Inc. We are actively pursuing a listing on the NASDAQ. 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 of EXXI Ltd
	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
Transition Period Ended December 31, 2016
Quarter Ended September 30, 2016		0.06		0.02
Quarter Ended December 31, 2016		0.22		0.02

Concurrently with the filing of the Bankruptcy Petitions and to streamline the business operations and organization structure following the emergence from Chapter 11 proceedings, EXXI Ltd filed a petition to commence the Bermuda Proceeding. On April 15, 2016, John C. McKenna was appointed as Provisional Liquidator by the Bermuda Court. In light of the emergence from the Chapter 11 Cases, the Bermuda Court granted the entry into a winding up order formally placing EXXI Ltd in liquidation and confirming John C. McKenna as Provisional Liquidator. The liquidation is expected to be completed during the first half of 2017, and EXXI Ltd will, at such conclusion, be dissolved. During the pendency of the Bermuda Proceeding, EXXI Ltd has adopted a modified reporting program with respect to its reporting obligations under federal securities laws. EXXI Ltd does not intend to file periodic reports while the Bermuda Proceeding is pending, but will continue to file current reports on Form 8-K as required by federal securities laws.

On December 30, 2016, the Company entered into the Registration Rights Agreement with parties who received 33,211,594 shares of the Company’s common stock upon the Emergence Date, representing 10% or more of the Company’s common stock outstanding on that date, or who acquire 10% or more of the Company’s common stock outstanding within six months of the Emergence Date. On or before the date that is 60 days after the Emergence Date, the Company has agreed to file, and will thereafter use its commercially reasonable efforts to cause to be declared effective as promptly as practicable, a registration statement on Form S-3 (or other appropriate form) for the offer and resale of the shares of the Company’s common stock

45

held by the such holders. The Company intends to be listed on the NASDAQ as soon as practicable. As of December 31, 2016, there was one holder of record of the Successor Company’s common stock.

Dividend Information

The Company does not anticipate any cash dividends or other distributions to be paid with respect to common stock in the foreseeable future.

Item 6. Selected Financial Data

We have derived the following selected consolidated financial information as of December 31, 2016, June 30, 2016 and 2015 and for the six month transition period ended December 31, 2016 and 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.

	Successor			Predecessor
	On December 31,			Six Months Ended December 31,			Year Ended June 30,
	2016(5)			2016(4)			2016			2015			2014(3)			2013			2012
							(In thousands, except per share amounts)
Income Statement Data
Revenues	$	—		$	295,676		$	706,527		$	1,405,452		$	1,153,123		$	1,158,932		$	1,504,611
Depreciation, depletion and amortization		—			60,626			339,516			705,521			414,026			363,791			350,569
Impairment of oil and natural gas properties		406,275			86,820			2,813,570			2,421,884			—			—			—
Goodwill impairment		—			—			—			329,293			—			—			—
Operating income (loss)		(406,275	)		(82,029	)		(3,017,425	)		(2,710,891	)		217,806			326,081			694,158
Other income (expense) – net(1)		—			(12,463	)		1,112,788			(336,297	)		(164,661	)		(112,704	)		(108,811	)
Net income (loss)		(406,275	)		2,653,903			(1,918,751	)		(2,433,838	)		18,125			180,783			478,808
Basic earnings (loss) per common share	$	(12.23	)	$	26.99		$	(20.11	)	$	(25.97	)	$	0.09		$	2.14		$	5.95
Diluted earnings (loss) per common share	$	(12.23	)	$	25.33		$	(20.11	)	$	(25.97	)	$	0.09		$	1.94		$	5.27
Cash Flow Data
Provided by (used in)
Operating activities	$	—		$	(17,473	)	$	(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		—			(20,237	)		(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		—			31,943			(13,925	)		1,751			(32,523	)		(16,734	)		4,728
Total investing activities		—			11,706			(122,913	)		(460,448	)		(1,544,575	)		(994,003	)		(569,593	)
Financing activities		—			(32,123	)		(264,022	)		740,737			1,144,921			238,768			(127,241	)
Increase (decrease) in cash		—			(37,890	)		(553,590	)		611,042			145,806			(117,087	)		88,680
Dividends Paid per Common Share	$	—		$	—		$	—		$	0.26		$	0.48		$	0.33		$	0.07

46

	Successor		Predecessor
	On December 31,		As of December 31,			As of June 30,
	2016		2016			2016			2015			2014(3)		2013		2012
						(In thousands)
Balance Sheet Data
Total assets	$	1,485,462	$	915,377		$	1,025,434		$	4,690,829		$	7,341,497	$	3,505,080	$	3,011,882
Long-term debt including current maturities(2)		78,497		2,837,785			2,863,844			4,608,432			3,759,644		1,370,045		1,018,344
Stockholders’ equity (deficit)		474,343		(2,802,050	)		(2,654,085	)		(728,722	)		1,734,560		1,367,935		1,286,776
Common shares outstanding		33,212		100,970			97,824			94,643			93,720		76,486		78,838

(1) The fiscal year ended June 30, 2016 includes $1,525.6 million in gain on early extinguishment of debt resulting from bond repurchases. See Note 9 — “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” of Notes to our Consolidated Financial Statements in this Form 10-K.

(3) On June 3, 2014, our Predecessor completed the EPL Acquisition, which significantly increased our scope of operation. See Note 5 — “Acquisitions and Dispositions” of Notes to our Consolidated Financial Statements in this Form 10-K.

(4) The six months ended December 31, 2016 includes a gain on the settlement of liabilities subject to compromise of $2,008.5 million, fair value adjustment gain of $830.5 and reorganization expenses of $90.6 million. See Note 4 — “Fresh Start Accounting” of Notes to our Consolidated Financial Statements in this Form 10-K.

(5) On the Convenience Date, subsequent to the restructuring adjustments and fair value adjustments, we recorded an impairment of our oil and natural gas properties of approximately $406.3 million, due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4-10.

	Successor		Predecessor
	On December 31,		Six Months Ended December 31,			Year Ended June 30,
Operating Highlights	2016		2016			2016			2015			2014			2013			2012
						(In thousands, except per unit amounts)
Operating revenues
Oil sales	$	—	$	258,573		$	546,766		$	1,052,731		$	1,104,208		$	1,067,687		$	1,186,193
Natural gas sales		—		37,103			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		—		295,676			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		—		87	%		89	%		90	%		89	%		90	%		93	%
Operating expenses
Lease operating expense
Insurance expense		—		12,596			37,958			40,046			31,183			32,737			28,521
Workover and maintenance		—		22,715			58,260			65,562			66,481			65,118			56,413

47

	Successor			Predecessor
	On December 31,			Six Months Ended December 31,			Year Ended June 30,
Operating Highlights	2016			2016			2016			2015			2014			2013			2012
							(In thousands, except per unit amounts)
Direct lease operating expense		—			108,385			249,855			357,927			268,083			239,308			225,881
Total lease operating expense		—			143,696			346,073			463,535			365,747			337,163			310,815
Production taxes		—			482			1,442			8,385			5,427			5,246			7,261
Gathering and transportation		—			19,551			55,925			21,144			23,532			24,168			16,371
DD&A		—			60,626			339,516			705,521			414,026			363,791			350,569
Accretion of asset retirement obligations		—			38,973			64,690			50,081			30,183			30,885			39,161
Impairment of oil and natural gas properties		406,275			86,820			2,813,570			2,421,884			—			—			—
Goodwill impairment		—			—			—			329,293			—			—			—
General and administrative		—			27,557			102,736			116,500			96,402			71,598			86,276
Total operating expenses		406,275			377,705			3,723,952			4,116,343			935,317			832,851			810,453
Operating income (loss)	$	(406,275	)	$	(82,029	)	$	(3,017,425	)	$	(2,710,891	)	$	217,806		$	326,081		$	694,157
Sales volumes per day
Natural gas (MMcf)		—			73.3			92.8			102.7			89.7			88.6			81.5
Crude oil (MBbls)		—			30.7			37.0			41.8			30.1			28.3			30.5
Total (MBOE)		—			42.9			52.5			58.9			45.0			43.1			44.1
Percent of sales volumes from crude oil		—			72	%		71	%		71	%		67	%		66	%		69	%
Average sales price
Oil per Bbl	$	—		$	45.77		$	40.36		$	68.99		$	100.59		$	103.48		$	106.17
Natural gas per Mcf		—			2.75			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		—			37.44			36.78			65.36			70.16			73.77			93.21
Operating expenses per BOE
Lease operating expense
Insurance expense		—			1.60			1.98			1.86			1.90			2.08			1.77
Workover and maintenance		—			2.88			3.03			3.05			4.04			4.15			3.49
Direct lease operating expense		—			13.72			13.01			16.64			16.31			15.23			13.99
Total lease operating expense per BOE		—			18.20			18.02			21.55			22.25			21.46			19.25

48

	Successor		Predecessor
	On December 31,		Six Months Ended December 31,			Year Ended June 30,
Operating Highlights	2016		2016			2016			2015			2014		2013		2012
						(In thousands, except per unit amounts)
Production taxes		—		0.06			0.08			0.39			0.33		0.33		0.45
Gathering and transportation		—		2.48			2.91			0.98			1.43		1.54		1.01
DD&A		—		7.68			17.67			32.81			25.19		23.16		21.72
Accretion of asset retirement obligations		—		4.94			3.37			2.33			1.84		1.97		2.43
Impairment of oil and natural gas properties		—		10.99			146.47			112.63			—		—		—
Goodwill impairment		—		—			—			15.31			—		—		—
General and administrative		—		3.49			5.35			5.42			5.87		4.56		5.34
Total operating expenses per BOE		—		47.84			193.87			191.42			56.91		53.02		50.20
Operating income (loss) per BOE	$	—	$	(10.40	)	$	(157.09	)	$	(126.06	)	$	13.25	$	20.75	$	43.01

49

	Predecessor
	Quarter Ended
Operating Highlights	December 31, 2016			September 30, 2016			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	$	133,697		$	124,876		$	133,079		$	95,081		$	139,698		$	178,908		$	225,263
Natural gas sales		19,368			17,735			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		153,065			142,611			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		87	%		88	%		90	%		87	%		89	%		88	%		90	%
Operating expenses
Lease operating expense
Insurance expense		6,287			6,309			8,269			8,312			10,042			11,335			8,963
Workover and maintenance		11,705			11,010			17,471			12,105			6,656			22,028			12,243
Direct lease operating expense		56,908			51,477			55,309			61,627			71,660			61,259			72,268
Total lease operating expense		74,900			68,796			81,049			82,044			88,358			94,622			93,474
Production taxes		268			214			155			221			309			757			1,492
Gathering and transportation		5,478			14,073			10,014			14,155			16,778			14,978			3,459
DD&A		29,053			31,573			40,078			53,847			121,567			124,024			183,279
Accretion of asset retirement obligations		19,536			19,437			18,905			15,057			15,944			14,784			12,358
Impairment of oil and natural gas properties		—			86,820			142,640			340,469			1,425,792			904,669			1,852,268
General and administrative		12,122			15,435			23,174			28,358			29,015			22,189			25,210
Total operating expenses		141,357			236,348			316,015			534,151			1,697,763			1,176,023			2,171,540
Operating income (loss)	$	11,708		$	(93,737	)	$	(168,211	)	$	(417,866	)	$	(1,513,148	)	$	(918,200	)	$	(1,952,080	)
Sales volumes per day
Natural gas (MMcf)		73.8			72.8			86.5			84.8			99.4			100.4			103.2
Crude oil (MBbls)		30.2			31.2			32.9			35.0			37.9			42.2			42.0
Total (MBOE)		42.5			43.4			47.3			49.1			54.5			58.9			59.3
Percent of sales volumes from crude oil		71	%		72	%		70	%		71	%		70	%		72	%		71%

50

	Predecessor
	Quarter Ended
Operating Highlights	December 31, 2016		September 30, 2016			June 30, 2016			March 31, 2016			December 31, 2015			September 30, 2015			June 30, 2015
	(In thousands, except per unit amounts)
Average sales price
Oil per Bbl	$	48.19	$	43.44		$	44.44		$	29.86		$	40.05		$	46.11		$	58.87
Natural gas per Mcf		2.85		2.65			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		39.19		35.73			34.32			26.01			36.83			47.57			40.70
Operating expenses per BOE
Lease operating expense
Insurance expense		1.61		1.58			1.92			1.86			2.00			2.09			1.66
Workover and maintenance		3.00		2.76			4.06			2.71			1.33			4.06			2.27
Direct lease operating expense		14.57		12.90			12.84			13.79			14.30			11.30			13.40
Total lease operating expense per BOE		19.18		17.24			18.82			18.36			17.63			17.45			17.33
Production taxes		0.07		0.05			0.04			0.05			0.06			0.14			0.28
Gathering and transportation		1.40		3.53			2.33			3.17			3.35			2.76			0.64
DD&A		7.44		7.91			9.31			12.05			24.26			22.88			33.99
Accretion of asset retirement obligations		5.00		4.87			4.39			3.37			3.18			2.73			2.29
Impairment of oil and natural gas properties		—		21.75			33.12			76.17			284.48			166.91			343.52
General and administrative		3.10		3.87			5.38			6.34			5.79			4.09			4.68
Total operating expenses per BOE		36.19		59.22			73.39			119.51			338.75			216.96			402.73
Operating income (loss) per BOE	$	3.00	$	(23.49	)	$	(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.

On the Petition Date, EXXI Ltd, an exempt company incorporated under the laws of Bermuda and predecessor of the registrant under this transition report on Form 10-K for the six month transition period ended December 31, 2016 (this “Form 10-K”), EGC, an indirect wholly-owned subsidiary of EXXI Ltd, EPL, an indirect wholly-owned subsidiary of EXXI Ltd and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11.

On December 13, 2016, the Bankruptcy Court entered the Confirmation Order and on December 30, 2016, the Debtors emerged from bankruptcy.

In connection therewith, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to the Reorganized EGC. In accordance with ASC 852, the Reorganized EGC applied fresh start accounting upon our Predecessor’s emergence from bankruptcy and it evaluated transaction activity between the Emergence Date and December 31, 2016 and concluded an accounting convenience date of December 31, 2016 (the “Convenience Date”) was appropriate.

As used throughout this Form 10-K, references to the “Reorganized EGC” “Company,” “we,” “our”, “Successor”, “Successor Company” or similar terms when used in reference to the period subsequent to the emergence from the bankruptcy refer to Reorganized EGC, the new parent entity and successor issuer of EXXI Ltd pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). References in this Form 10-K to “EXXI Ltd,” “we,” “our”, “Predecessor”, “Predecessor Company” or similar terms when used in reference to the periods prior to the emergence from the bankruptcy refer to Energy XXI Ltd, the predecessor and former parent entity that will be dissolved upon the completion of the Bermuda Proceeding (as defined below). References in this Form 10-K to “EGC” refer to Energy XXI Gulf Coast, Inc. in the periods prior to the emergence from the bankruptcy during which it was the wholly-owned operating subsidiary of EXXI Ltd.

On February 7, 2017, the Board adopted a resolution to change the Company’s fiscal year end from June 30 to December 31. As a result, this Form 10-K is a transition report and includes financial information for the transition period from July 1, 2016 through December 31, 2016. Subsequent to this report, our reports on Form 10-K will cover the calendar year, January 1 to December 31, which will be our fiscal year. Unless otherwise noted, all references to “years” in this Form 10-K refer to the twelve-month fiscal year, which, prior to July 1, 2016 ended on June 30, and, beginning after June 30, 2016, ends on December 31.

The audited financial statements of the Successor on December 31, 2016 reflect an impairment of our oil and natural gas properties of approximately $406.3 million which we recognized due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4-10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12-month average oil and gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. The audited financial statements for the six month transition period ended December 31, 2016 and EXXI Ltd’s prior fiscal years ended June 30, 2016, 2015 and 2014 contained herein include a summary of its significant accounting policies and should be read in conjunction with the discussion below. In the opinion of management, all material adjustments necessary to present fairly the results of operations for such periods have been included in these financial statements.

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Overview

We are headquartered in Houston, Texas and have historically engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the GoM Shelf.

We have historically focused on development and extension drilling on our existing core properties to enhance production and ultimate recovery of reserves, supplemented by exploration and 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 drilling opportunities in our geographic area of expertise.

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 may provide us with opportunities to place service work out to bid to obtain better services and prices.

At December 31, 2016, our total proved reserves were 121.9 MMBOE of which 81% were oil and 70% were classified as proved developed. We operated or had an interest in 616 gross producing wells on 439,294 net developed acres, including interests in 57 producing fields. We believe operating our assets is a key to our success and approximately 91% 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 low prices continuing throughout fiscal year 2016. In response to that decline, EXXI Ltd executed a series of financial and operational activities to address its debt burden and liquidity issues, including reducing capital expenditures, reducing field level operating costs by over 30% from fiscal year 2015, repurchasing our debt at substantial discounts, monetizing hedges and sales of non-core assets.

As a result of continued decreases in commodity prices and EXXI Ltd’s prior 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 and the Debtors ultimately filed the Bankruptcy Petitions seeking relief under Chapter 11 on April 14, 2016. Thereafter until emergence the Debtors 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. See additional details regarding our emergence from bankruptcy below under the heading “— Emergence from Chapter 11”.

During 2016, WTI prices ranged from $26.21 to $54.06 per Bbl and the Henry Hub spot market price of gas ranged from $1.64 to $3.93 per MMBtu. Oil prices have begun to recover and reached a high of $53.99 per barrel and the Henry Hub spot market price of natural gas reached a high of $3.42 per MMBtu in January 2017. With the price of oil below $55 a barrel, the level at which many energy companies expect to make a profit, the cost to hire an experienced drilling crew and source critical oil-field supplies may increase if the price of oil keeps increasing. For the calendar year 2017, the Company’s initial capital budget, excluding acquisitions but including plugging and abandonment is expected to be in the range of $140 million to $170 million, of which plugging and abandonment costs are expected to be in the range of $50 million to $70 million. In February 2017, we entered into oil contracts (costless collars) benchmarked to Argus-LLS, to hedge 10,000 BPD of our production for the period from March 2017 to December 2017 with an average floor price of $52.30 and an average ceiling price of $57.43. If the prices of oil and natural gas reverse their recent increases, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected.

Emergence from Chapter 11

On the Petition Date, the Debtors filed voluntary petitions for reorganization in the Bankruptcy Court seeking relief under Chapter 11 under the caption In re Energy XXI Ltd, et al., Case No. 16-31928. As a result of filing of the Bankruptcy Petitions, EXXI Ltd common stock was delisted from the NASDAQ and on

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May 19, 2016, its registration under Section 12(b) of the Exchange Act was withdrawn. As a result, EXXI Ltd’s common stock was deemed registered pursuant to Section 12(g) of the Exchange Act pursuant to Exchange Act Rule 12g-2(b).

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 Objection Deadline and Hearing Relating to Confirmation of the Plan and (C) Granting Related Relief. On July 18, 2016, the Debtors filed the Disclosure Statement.

On November 21, 2016, the Debtors filed the Plan and the Disclosure Statement Supplement.

On November 21, 2016, the Bankruptcy Court entered the Order (A) Approving the Adequacy of the Disclosure Statement Supplement to the Debtors’ Third Amended Disclosure Statement Setting Forth Modifications to the Debtors’ Plan and the Continued Solicitation of the Plan and (B) Granting Related Relief approving updated solicitation and tabulation procedures with respect to the Plan.

On December 13, 2016, the Bankruptcy Court entered the Confirmation Order, which approved and confirmed the Plan as modified by the Confirmation Order.

On December 30, 2016, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Reorganized Debtors emerged from Chapter 11. In connection with the satisfaction of the conditions to effectiveness as set forth in the Confirmation Order and in the Plan, EXXI Ltd and EGC completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to Reorganized EGC, as the new parent entity. Accordingly, Reorganized EGC succeeded to the entire business and operations previously consolidated for accounting purposes by EXXI Ltd.

Concurrently with the filing of the Bankruptcy Petitions, EXXI Ltd filed a petition seeking an order for liquidation of EXXI Ltd in the Bermuda Court. On April 15, 2016, John C. McKenna was appointed as Provisional Liquidator by the Bermuda Court. In light of the Plan and the emergence of EXXI Ltd from Chapter 11, the Bermuda Court granted the entry into a winding up order formally placing EXXI Ltd in liquidation and confirming John C. McKenna as Provisional Liquidator. The liquidation is expected to be completed during the first half of 2017, and EXXI Ltd will, at such conclusion, be dissolved. During the pendency of the Bermuda Proceeding, EXXI Ltd has adopted a modified reporting program with respect to its reporting obligations under federal securities laws. EXXI Ltd does not intend to file periodic reports while the Bermuda Proceeding is pending, but will continue to file current reports on Form 8-K as required by federal securities laws.

Fresh Start Accounting

Upon emergence from bankruptcy, in accordance with ASC 852 related to fresh-start accounting, Reorganized EGC became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Convenience Date. The Convenience Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in the Predecessor historical consolidated balance sheets. The effects of the Plan and the application of fresh-start accounting are reflected in our consolidated balance sheet as of December 31, 2016 and the related adjustments thereto were recorded in the consolidated statement of operations of the Predecessor as reorganization items during the six month transition period ended December 31, 2016. Accordingly, Reorganized EGC’s consolidated financial statements as of and subsequent to December 31, 2016 are not and will not be comparable to the Predecessor consolidated financial statements prior to the Convenience Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on December 31, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

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Plan of Reorganization

In accordance with the Plan, the following significant transactions occurred:

Prepetition Notes

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the following notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled:

• 11.0% senior secured second lien notes due March 15, 2020 (the “Second Lien Notes”) issued pursuant to that certain Indenture, dated as of March 12, 2015, among EGC, the guarantors party thereto, and U.S. Bank, N.A., as trustee, and all amendments, supplements or modifications thereto and extensions thereof;

• 6.875% senior unsecured notes due March 15, 2024 (the “EGC 6.875 Senior Notes”) issued pursuant to that certain indenture, dated May 27, 2014, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof;

• 7.50% senior unsecured notes due December 15, 2021 (the “EGC 7.50% Senior Notes”) issued pursuant to that certain indenture, dated September 26, 2013, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof;

• 7.75% senior unsecured notes due June 15, 2019 (the “EGC 7.75% Senior Notes”) issued pursuant to that certain indenture, dated February 25, 2011, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof;

• 9.25% senior unsecured notes due December 15, 2017 (the “EGC 9.25% Senior Notes,” and together with the EGC 6.875% Senior Notes, the EGC 7.50% Senior Notes, the EGC 7.75% Senior Notes and the “EGC Unsecured Notes”) issued pursuant to that certain indenture, dated December 17, 2010, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof;

• 8.25% senior unsecured notes due February 15, 2018 (the “EPL 8.25% Senior Notes”) issued pursuant to that certain indenture, dated as of February 14, 2011, by and EGC, the guarantors party thereto, and U.S. Bank National Association, as trustee, and all amendments, supplements or modifications thereto and extensions thereof; and

• 3.0% senior convertible notes due on December 15, 2018 (the “EXXI 3.0% Senior Convertible Notes”) issued pursuant to that certain indenture dated as of November 22, 2013 among EXXI Ltd and Wilmington Savings Fund Society, FSB, as trustee, and all amendments, supplements or modifications thereto and extensions thereof.

Prepetition Revolving Credit Facility and Exit Facility

On the Emergence Date, by operation of the Plan, all outstanding obligations under the “Prepetition Credit Agreement” or Prepetition Revolving Credit Facility and the related collateral agreements were cancelled, and the credit agreement governing such obligations was cancelled.

Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three-year secured Exit Facility with the majority of lenders under the Prepetition Revolving Credit Facility. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) the Exit Term Loan resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Prepetition Revolving Credit Facility of approximately $74 million and (ii) the Exit Revolving Facility resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides for the making of revolving loans

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and the issuance of letters of credit. On the Emergence Date, the aggregate commitments under the Exit Revolving Facility were approximately $227.8 million, all of which will be utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of ExxonMobil to secure certain plugging and abandonment obligations related to assets in the Gulf of Mexico. On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with ExxonMobil, it was agreed that subsequent to the Predecessor Company’s emergence from the Chapter 11 proceedings, the letters of credit issued in favor ExxonMobil would be reduced to $200 million from the existing amount of $225 million and currently documents are being formalized to effect such reduction. As of December 31, 2016, we had no available borrowing capacity under the Exit Facility For more information, please read “— Liquidity and Capital Resources — Exit Facility” below.

Equity Interests

As a result of the Plan, there are no assets remaining in EXXI Ltd, and under Bermuda law, shareholders (including preferred shareholders) of EXXI Ltd will receive no payments and all of its existing share-based compensation plans were also cancelled. EXXI Ltd will be dissolved at the conclusion of the Bermuda Proceeding, and as such, the shareholders will no longer have any interest in EXXI Ltd as a matter of Bermuda law.

On the Emergence Date, the Company issued 100% of its shares of common stock to certain of the Debtors’ creditors pursuant to the Plan. The Company issued (i) 27,897,739 shares of common stock, pro rata, to holders of the claims arising from the Second Lien Notes, (ii) 3,985,391 shares of common stock, pro rata, to holders of the claims arising from the EGC Unsecured Notes (the “EGC Unsecured Notes Claims”), (iii) 1,328,464 shares of common stock, pro rata, to holders of the claims arising from the EPL 8.25% Senior Notes (the “EPL Unsecured Notes Claims”), (iv) 1,271,933 warrants, pro rata, to holders of the EGC Unsecured Notes Claims; and (v) 847,956 warrants, pro rata, to holders of the EPL Unsecured Notes Claims. The Confirmation Order and Plan provide for the exemption of the offer and sale of the shares of the Company’s common stock and warrants (including shares of the Company’s common stock issuable upon the exercise thereof) from the registration requirements of the Securities Act of 1933 (the “Securities Act”) pursuant to Section 1145(a)(1) of the Bankruptcy Code. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied.

Warrant Agreement

On the Emergence Date, the Company entered into the Warrant Agreement with Continental Stock Transfer & Trust Company, as Warrant Agent. Pursuant to the terms of the Plan, on the Emergence Date, the Company issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims.

The warrants are exercisable from the date of the Warrant Agreement until 5:00 p.m., New York City time, on December 30, 2021 (the “Expiration Date”). The warrants are initially exercisable for one share of the Company’s common stock per warrant (such rate, as adjusted pursuant to the Warrant Agreement, being the “Warrant Exercise Shares”) at an initial exercise price of $43.66 (the “Exercise Price”). The Warrant Exercise Shares and Exercise Price are subject to customary anti-dilution adjustments. No adjustments to the applicable Exercise Price or Warrant Exercise Shares are required unless the cumulative adjustments required would result in an increase or decrease of at least 1.0% in the applicable Exercise Price or the Warrant Exercise Shares. Additionally, if an adjustment in Exercise Price would reduce the Exercise Price to an amount below par value of the Company’s common stock, then such adjustment in Exercise Price will reduce the Exercise Price to the par value of the Company’s common stock.

Upon the occurrence of certain events prior to the Expiration Date constituting a recapitalization, reorganization, reclassification, consolidation, merger, sale of all or substantially all of the Company’s equity securities or assets or other transaction, in each case which is effected in such a way that the holders of the Company’s common stock are entitled to receive (either directly or upon subsequent liquidation) cash, stock, securities or other assets or property with respect to or in exchange for shares of the Company’s common stock (any such event, “Organic Change”), each holder of warrants will be entitled to receive, upon exercise of a warrant, such cash, stock, securities or other assets or property as would have been issued or payable in

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such Organic Change (as if the holder had exercised such warrant immediately prior to such Organic Change) with respect to or in exchange, as applicable, for the number of Warrant Exercise Shares that would have been issued upon exercise of such warrants, if such warrants had been exercised immediately prior to the occurrence of such Organic Change.

Holders of warrants are not entitled, by virtue of holding warrants, to vote, to consent, to receive dividends, to consent or to receive notice as stockholders with respect to any meeting of stockholders for the election of the Company’s directors or any other matter, or to exercise any rights whatsoever as the Company’s stockholders unless, until and only to the extent such holders become holders of record of shares of the Company’s common stock issuable upon exercise of the warrants.

The warrants permit a holder of warrants to exercise the warrants for net share or “cashless” settlement in lieu of paying the Exercise Price by authorizing the Company to withhold and not issue to such holder, in payment of the Exercise Price, a number of such Warrant Exercise Shares equal to (i) the number of Warrants Exercise Shares for which the warrants are being exercised, multiplied by (ii) the Exercise Price, and divided by (iii) the Current Sale Price (as defined in the Warrant Agreement) on the Exercise Date (as defined in the Warrant Agreement).

Non-Continuing EXXI Ltd Directors

Pursuant to the Plan, as of the Emergence Date, the following directors resigned from EXXI Ltd’s board of directors: William Colvin, Cornelius Dupré II, Hill A. Feinberg, Kevin Flannery, Scott A. Griffiths and James LaChance. On January 3, 2017, John D. Schiller, Jr. also resigned from EXXI Ltd’s board of directors. Following the resignation of all of the directors of EXXI Ltd and in accordance with Bermuda law, the Provisional Liquidator assumed full control of EXXI Ltd’s affairs and will continue to do so until the liquidation of EXXI Ltd is complete.

Departure and Appointment of Company Directors

Upon the effectiveness of the Plan, Bruce W. Busmire resigned as director of EGC. On the Emergence Date, by operation of the Plan, Michael S. Bahorich, George Kollitides, Steven Pully, Michael S. Reddin, James “Jay” W. Swent III and Charles W. Wampler joined John D. Schiller, Jr., an existing director of EGC, were appointed as members of the Board.

On February 2, 2017, John D. Schiller, Jr. resigned from his position as President and Chief Executive Officer (“CEO”) of the Company and also ceased to serve as a member of the Board. As a result, on February 2, 2017, the Board appointed Michael S. Reddin, the Company’s Chairman of the Board, to serve as the Company’s President and CEO on an interim basis. Mr. Reddin will continue to serve as Chairman of the Board. Because Mr. Reddin is now serving as both as Chairman of the Board and CEO, the Board has amended and restated the Company’s bylaws to provide for a Lead Independent Director and has appointed director James “Jay” W. Swent III to serve in that capacity. In order to eliminate the Board vacancy created by Mr. Schiller’s departure from the Board, the size of the Board was reduced from seven to six on February 2, 2017.

For more information, please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance.”

Departure and Appointment of Company Officers and Long Term Incentive Plan

In accordance with the Plan, prior to the Emergence Date, the following officers of EXXI Ltd were appointed as officers of the Company: John D. Schiller, Jr. — Chief Executive Officer and President, Bruce W. Busmire — Chief Financial Officer, Antonio de Pinho — Chief Operating Officer and Hugh Menown — Executive Vice President, Chief Accounting Officer. On February 2, 2017, Mr. Schiller, Mr. Busmire and Mr. de Pinho resigned as President and CEO, Chief Financial Officer and Chief Operating Officer, respectively. As a result, on February 2, 2017, the Board appointed (i) Scott M. Heck to join the Company as the Company’s new COO to succeed Mr. de Pinho and (ii) Hugh A. Menown, the Company’s current Executive Vice President and Chief Accounting Officer, as the Company’s CFO on an interim basis to succeed Mr. Busmire.

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As of the Emergence Date, the Company also entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the go-forward compensation for the Reorganized Debtors’ officers, directors, employees and consultants and an employment agreement with our former President and CEO, John D. Schiller, Jr. In connection with his termination of employment, the Schiller Employment Agreement was terminated as of February 2, 2017. On February 2, 2017, the Company entered into the Schiller Consulting Agreement with Mr. Schiller, pursuant to which Mr. Schiller has agreed to serve as a special advisor to the Board during a transition period of up to six months. In consideration for those services, the Company has agreed to pay Mr. Schiller a consulting fee equal to $50,000 per month.

Additionally, the Company entered into employment agreements with Scott M. Heck and Michael S. Reddin as our COO and Interim President and CEO, respectively. For more information, please read Part III, Item 11. “Executive Compensation — Long Term Incentives” and Part III, Item 11. “Executive Compensation — Potential Payments upon Termination or a Change in Control.”

For more information, please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance.”

Amendments to Articles of Incorporation or Bylaws

Pursuant to the Plan, on the Emergence Date, the Company’s certificate of incorporation and bylaws were amended and restated in their entirety. Each of the Company’s Second Amended and Restated certificate of incorporation and the second amended and restated bylaws became effective on the Emergence Date. Under our Certificate of Incorporation, the total number of all shares of capital stock that the Company is authorized to issue is 110 million shares, consisting of 100 million shares of the Company’s common stock, par value $0.01 per share, and 10 million shares of preferred stock, par value $0.01 per share.

In order to permit Mr. Reddin to be appointed CEO on an interim basis, the Board adopted the Third Amended and Restated Bylaws (the “Bylaws”) on February 2, 2017. Pursuant to the Bylaws, Section 4.1 was amended to provide that the positions of Chairman of the Board and Chief Executive Officer may be held by the same person only if (i) the two positions are held by the same person solely on an interim basis and (ii) the Board elects a Lead Independent Director for any period in which the two positions are held by the same person. Accordingly, the Bylaws added a new Section 3.8 to establish the position of Lead Independent Director and specified that position’s duties. The Bylaws provide that, during any period in which a Lead Independent Director is serving, the Lead Independent Director may, among other responsibilities, call and preside over all meetings of independent directors and, in the Chairman of the Board’s absence, preside over all meetings of the Company’s stockholders and of the Board.

After adopting the Bylaws, the Board appointed James “Jay” W. Swent III to serve as Lead Independent Director. Mr. Swent is an existing member of the Board, and will continue to serve as chairman of the Audit Committee of the Board. Mr. Swent has more than 35 years of global business and senior leadership experience.

While the emergence from bankruptcy is effectively complete, certain administrative activities will continue under the authority of the Bankruptcy Court for the next several months.

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 2015 and the decline continued with lower prices into 2016. The posted price per barrel for West Texas intermediate light sweet crude oil, or WTI, for the period from October 1, 2014 to December 31, 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 December 31, 2016 ranged from a high of $4.49 to a low of $1.64, a decrease of 63.5%. As of December 31, 2016, the spot market price for WTI was $53.72. Oil prices remained depressed in most of 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 $50.00 per barrel in February 2017, there is still significant volatility in commodity prices and these prices are still significantly lower than the industry has experienced in recent years. Further declines in oil and natural

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gas prices may adversely affect our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce. If the prices of oil and gas reverse their recent increases, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected.

Reduced Capital Spending.  With the continued market instability between July 2014 through the majority of 2016, 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 was not economically feasible to undertake capital intensive projects at those prices. For the calendar year 2017, the Company’s initial capital budget, excluding acquisitions but including plugging and abandonment is expected to be in the range of $140 million to $170 million, of which plugging and abandonment costs are expected to be in the range of $50 million to $70 million.

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 December 31, 2016, our total proved reserves were 121.9 MMBOE. The unweighted arithmetic average first-day-of-the-month prices adjusted for differentials used to determine our reserves as of December 31, 2016 were $41.51 per barrel of oil, $21.63 per barrel for NGLs and $2.29 per MMBtu for natural gas.

Due to the depressed commodity prices and EXXI Ltd’s lack of capital resources to develop its properties, all of its proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result, EXXI Ltd removed all of its 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 were still economic at prices and costs applicable to SEC reserve reports at such date, 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 then current constraints on EXXI Ltd’s ability to fund development drilling. Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million. As scheduled in our long range plan, substantially all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report.

Ceiling Test Write-down.  On December 31, 2016, subsequent to our emergence from bankruptcy, we recorded an impairment of our oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4-10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12-month average oil and gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. Further ceiling test write-downs will be required if oil and natural gas prices decline, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and natural gas properties otherwise exceeds the present value of estimated future net cash flows.

Service Costs Fluctuations.  Due to the depressed commodity price environment, there was a significant and continuing reduction in rig rates and drilling costs, which allowed EXXI Ltd to spend less capital on drilling our development wells than in prior periods. However, with the price of oil below $55 a barrel, the level at which many energy companies expect to make a profit, the cost to hire an experienced drilling crew and source critical oil-field supplies may increase if the price of oil keeps increasing.

BOEM Supplemental Financial Assurance and/or Bonding Requirements.  As of December 31, 2016, we had $388.2 million of performance bonds outstanding and $225 million in letters of credit issued to ExxonMobil 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

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by the BSEE and the BOEM. These leases require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws. In particular, compliance with lease requirements includes responsibility for decommissioning obligations 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, and the BOEM generally requires that lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. In July 2016, the BOEM issued a new NTL that provided more stringent requirements for additional security to satisfy decommissioning obligations and eliminating previous exemptions from the posting of financial assurances. Consequently, as of December 31, 2016, we have submitted approximately $226.7 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 $226.7 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 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 conditions of the Long-Term Plan, we have submitted supplemental bonds to the BOEM for our sole liability properties addressed under the Long-Term Plan; however, the BOEM increased the financial assurance amount for one of those sole liability properties subsequent to execution of the Long Term Plan and, thus, on June 28, 2016, we submitted the Proposed Plan Amendment that would revised the Long-Term Plan and reflect such increase (the “Proposed Plan Amendment”), and we are awaiting the BOEM’s further response on the Proposed Plan Amendment.

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 (July 1, 2017 under the Proposed Plan Amendment), or submit to the BOEM a plan for providing to the BOEM other satisfactory forms of financial assurance with respect to those properties covered by such third-party bonds, for which EGC had submitted to the BOEM for review; (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, LLC (“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

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achieve full financial assurance for certain of such offshore facility interests by submitting a plan for these properties by July 1, 2016 (July 1, 2017 under the Proposed Plan Amendment); (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 Proposed Plan Amendment, we would continue to pursue, among other things, certain of the tasks described above in a manner as further set forth in the Proposed Plan Amendment. We are currently awaiting the BOEM’s further response on the Proposed Plan Amendment.

Consistent with the BOEM’s issuance of the new NTL in July 2016 that went into effect September 12, 2016 (the “September 2016 NTL”) relating to the need for additional security to satisfy decommissioning obligations and its and its subsequent announcement that it was extending the implementation timeline for providing financial assurance under the September 2016 NTL by an additional six months (the “January 2017 Extension”), however, the BOEM’s current focus is on sole liability properties. Consequently, the BOEM issued a letter to us dated January 5, 2017, ordering us to provide BOEM with additional security for certain sole liability properties in the OCS that are held or operated by us in the OCS and specified in the letter within 60 calendar days of receipt of the letter (the “January 5, 2017 Ordering Letter”). The amount of additional security required of us under the January 5, 2017 Ordering Letter is approximately $5.1 million. On January 26, 2017, the Company submitted to the BOEM its January 2017 Proposed Plan Amendment that would satisfy the January 5, 2017 Ordering Letter for approximately $5.1 million in additional sole liability property coverage while reserving the Company’s right to dispute the decommissioning liability amount calculated by the BSEE (the “January 2017 Proposed Plan Amendment”). Consequently, while we have submitted or plan to submit additional supplemental bonds to the BOEM for our sole liability properties addressed under the Long-Term Plan, and are awaiting the BOEM’s response on the Proposed Plan Amendment and the January 2017 Proposed Plan Amendment, we have not yet been directed by the BOEM to submit financial assurance for our sole and non-sole liability properties (that is, our offshore OCS properties that are not sole liability properties) addressed under the Long-Term Plan.

In a recent development, however, the BOEM publicly announced on February 17, 2017 that it will withdraw sole liability orders previously issued to OCS lease and grant holders in December 2016 and January 2017 to allow time for the new Presidential Administration to review the BOEM’s current financial assurance program, as modified in 2016 by NTL 2016-N01. Whether, and to what extent, orders for non-sole liability properties will be re-issued by the BOEM will be re-evaluated in conjunction with the evaluation currently underway for OCS non-sole liability properties ordered by the BOEM as part of the six-month extension granted by the BOEM in January 2017. The BOEM may elect to re-issue its sole liability orders before the end of the six-month extended period established for the non-sole liability properties if the agency determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

Due to the BOEM’s recent retractions in the first two months of 2017 relating to the provision of financial assurance for OCS decommissioning obligations, we are currently uncertain as to the timing and amount of coverage that will be required by the BOEM pursuant to its OCS financial assurance program. However, based on currently understood parameters as reflected in the Long-Term Plan and the Proposed Plan Amendment, we currently expect to ultimately address the financial coverage of our sole liability and non-sole liability properties in accordance with the Long-Term Plan and consistent with evolving guidelines under the September 2016 NTL, but we cannot provide any assurance at this time on when such financial coverage for our non-sole liability properties will be directed to be submitted by the BOEM or on how we plan to structure and fund such coverages.

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On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with ExxonMobil, it was agreed that subsequent to the Company’s emergence from the Chapter 11 Cases, the letters of credit issued in favor of ExxonMobil would be reduced to $200 million from the existing amount of $225 million and currently documents are being formalized to effect such reduction.

Notwithstanding the BOEM’s July 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, as it may be revised by the Proposed Plan Amendment or other amendments, the September 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 have $49.6 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors as of December 31, 2016, we may be required to provide additional cash collateral in the future to support the issuance of such bonds or other financial security. 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 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.

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, EXXI Ltd 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 L.P. (“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, Energy XXI GIGS Services, LLC (the “Tenant”) entered into a triple-net lease (the “GIGS Lease”) with Grand Isle Corridor pursuant to which it operates 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

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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. On December 30, 2016, the Tenant, the Company and Grand Isle Corridor entered into an Assignment and Assumption Agreement pursuant to which the Tenant assigned to the Company its right, title, interest, and obligations in and to the purchase and sale agreement relating to the GIGS. Additionally, Reorganized EGC assumed the obligations of EXXI Ltd as guarantor of Tenant’s obligations under the GIGS Lease pursuant to the Assignment and Assumption of Guaranty and Release Agreement, dated December 30, 2016.

Under the terms of the GIGS Lease, EGC was to 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 EXXI Ltd of a Bankruptcy Petition or (ii) the failure of either the Tenant or EXXI Ltd to make any payment of principal or interest with respect to certain material debt of the Tenant or EXXI Ltd, as the former 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, the Debtors’ filing of the Bankruptcy Petitions and failure to comply with our material debt instruments, would, among other things, have allowed Grand Isle Corridor to terminate the Lease.

As a result, the Tenant and Grand Isle Corridor entered into a waiver to the GIGS Lease, dated as of April 13, 2016, 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.

Sale of interests in the East Bay field

On June 30, 2015, the Predecessor 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. The Predecessor 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 acquisition of EPL Oil & Gas, Inc. (See “Acquisition of EPL” below).

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 $6.4 million. The final settlement occurred in January 2017.

Purchase of interests in M21K, LLC

On August 11, 2015, our Predecessor 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, the Predecessor Company had owned a 20% interest in M21K through our investment in EXXI M21K, LLC. See Note 5 — “Acquisitions and Dispositions” and Note 8 — “Equity

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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, our Predecessor completed the acquisition of EPL Oil & Gas, Inc. for approximately $2,500 million, including the assumption of debt (the “EPL Acquisition”), pursuant to which it 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 EXXI Ltd common shares and consisted of approximately $1,010 million in cash and approximately 23.3 million common shares of EXXI Ltd. Upon closing, EXXI Ltd 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 5 — “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

On December 31, 2016 for Successor Company

On the Convenience Date, subsequent to the restructuring adjustments and fair value adjustments, we recorded an impairment of our oil and natural gas properties of approximately $406.3 million, due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4-10.

The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12-month average oil and natural gas prices used in the calculation of limitation on capitalized costs.

Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting.

The impairment of our oil and natural gas properties did not impact our cash flows from operations but resulted in the Company’s net loss on December 31, 2016.

Six Month Transition Period Ended December 31, 2016 Compared With the Six Months Ended December 31, 2015

EXXI Ltd’s consolidated net income attributable to common stockholders for the six months ended December 31, 2016 was $2,653.9 million or $25.33 diluted net income per common share (“per share”) as compared to a net loss of $1,889.6 million or $19.91 per share for the six months ended December 31, 2015. The result of a net income for the six months ended December 31, 2016 was primarily due to recording of gains on reorganization and fair value adjustments and lower lease operating expense, lower depreciation, depletion and amortization (“DD&A”), lower impairment of oil and natural gas properties, lower general and administrative expenses and lower interest expense.

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Revenues

	Predecessor
	Six Months Ended December 31,				Decrease			Percent Decrease
	2016		2015
	(Unaudited)
	(In thousands)
Oil	$	258,573	$	318,606	$	(60,033	)		(18.8	%)
Natural gas		37,103		40,100		(2,997	)		(7.5	%)
Gain on derivative financial instruments		—		83,732		(83,732	)		(100.0	%)
Total Revenues	$	295,676	$	442,438	$	(146,762	)		(33.2	%)

Our consolidated revenues decreased $146.8 million for the six months ended December 31, 2016 as compared to the same prior period. Lower revenues were primarily due to lower production 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

	Predecessor
	Six Months Ended December 31,						Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
	2016			2015
				(Unaudited)									(In thousands)
Price Variance
Oil sales prices (per Bbl)(1)	$	45.77		$	43.24		$	2.53			5.9	%	$	18,640
Natural gas sales prices (per Mcf)(1)		2.75			2.18			0.57			26.1	%		10,487
Gain on derivative financial instruments (per BOE)		—			8.03			(8.03	)		(100.0	%)		(83,732	)
Total price variance														(54,605	)
Volume Variance
Oil sales volumes (MBbls)		5,649			7,368			(1,719	)		(23.3	%)		(78,673	)
Natural gas sales volumes (MMcf)		13,485			18,385			(4,900	)		(26.7	%)		(13,484	)
BOE sales volumes (MBOE)		7,897			10,432			(2,535	)		(24.3	%)
Percent of BOE from oil		72	%		71	%
Total volume variance														(92,157	)
Total price and volume variance													$	(146,762	)

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

Price Variances

Revenues declined by $54.6 million for the six months ended December 31, 2016 as compared to the same prior period. Average oil prices increased $2.53 per barrel for the six months ended December 31, 2016 as compared to the same prior period, resulting in higher revenues of $18.6 million. Average natural gas prices increased $0.57 per Mcf for the six months ended December 31, 2016 as compared to the same prior period, resulting in higher revenues of $10.5 million. We had no derivative gain for the six months ended December 31, 2016, compared to a gain of $8.03 per BOE for the same prior period in the prior fiscal year, resulting in lower revenues of $83.7 million. The gain on derivatives for the six months ended December 31, 2015 reflects a gain on settlements of our derivative contracts of approximately $5.34 per barrel of oil.

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Volume Variances

Oil sales volumes decreased 9.3 MBbls per day for the six months ended December 31, 2016 as compared to the same prior period, resulting in lower revenues of $78.7 million, while natural gas sales volumes decreased by 26.6 Mcf per day for the six months ended December 31, 2016, resulting in lower revenues of $13.5 million. Sales volumes decreased because of natural well declines, reduced drilling activity resulting in less new production, and irregular downtime due to third party pipelines. In the 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

	Predecessor
	Six Months Ended December 31,												Change Total $
	2016						2015
	Total $			Per BOE			Total $			Per BOE
	(Unaudited)
	(In thousands, except per unit amounts)
Cost and expenses
Lease operating expense
Insurance expense	$	12,596		$	1.60		$	21,377		$	2.05		$	(8,781	)
Workover and maintenance		22,715			2.88			28,684			2.75			(5,969	)
Direct lease operating expense		108,385			13.72			132,919			12.74			(24,534	)
Total lease operating expense		143,696			18.20			182,980			17.54			(39,284	)
Production taxes		482			0.06			1,066			0.10			(584	)
Gathering and transportation		19,551			2.48			31,756			3.04			(12,205	)
DD&A		60,626			7.68			245,591			23.54			(184,965	)
Accretion of asset retirement obligations		38,973			4.94			30,728			2.95			8,245
Impairment of oil and natural gas properties		86,820			10.99			2,330,461			223.40			(2,243,641	)
General and administrative		27,557			3.49			51,204			4.91			(23,647	)
Total costs and expenses	$	377,705		$	47.84		$	2,873,786		$	275.48		$	(2,496,081	)
Other income (expense)
Loss from equity method investees	$	—		$	—		$	(10,746	)	$	(1.03	)	$	10,746
Other income, net		117			0.01			3,048			0.29			(2,931	)
Gain on early extinguishment of debt		—			—			748,574			71.76			(748,574	)
Interest expense		(12,580	)		(1.59	)		(193,452	)		(18.54	)		180,872
Total other income (expense), net	$	(12,463	)	$	(1.58	)	$	547,424		$	52.48		$	(559,887	)

Costs and expenses decreased $2,496.1 million for the six months ended December 31, 2016 as compared to the same prior period, principally due to the lower lease operating expenses, lower DD&A, lower impairment of oil and natural gas properties and lower general and administrative expenses principally due to factors discussed further below.

Lease operating expense decreased $39.3 million for the six months ended December 31, 2016 as compared to the same prior period. 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 increased by $0.66 per BOE for the six months ended December 31, 2016 principally due to low production volumes in the current period as compared to the same prior period.

Gathering and transportation expense decreased $12.2 million for the six months ended December 31, 2016 as compared to the same prior period. This decrease was principally due to recording a receivable of approximately $7.8 million for excess transportation deductions by the Office of Natural Resources Revenue in prior periods.

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DD&A expense decreased $185.0 million for the six months ended December 31, 2016 as compared to the same prior period, primarily due to a decrease in the DD&A per BOE rate of $15.86. The decrease in the DD&A rate for the six months ended December 31, 2016 as compared to the same prior period was primarily due to the reduction in our full cost pool due to the impairments of our oil and natural gas properties in prior quarterly periods of fiscal years 2015 and 2016.

As a result of our ceiling test at September 30, 2016, we recognized an impairment of our oil and natural gas properties totaling $86.8 million during the six months ended December 31, 2016 and as a result of our ceiling tests at September 30, 2015 and December 31, 2015, we recognized impairments of our oil and natural gas properties totaling $2,330.5 million during the six months ended December 31, 2015.

General and administrative expense decreased $23.6 million for the six months ended December 31, 2016 as compared to the same prior period, primarily due to lower employee salary and stock based compensation costs, partially offset by lower capitalized amounts.

Interest expense decreased $180.9 million for the six months ended December 31, 2016 as compared to the same prior period, principally due to the discontinuance of recording interest on debt classified as liabilities subject to compromise on the Petition Date in accordance with ASC 852. On a per unit of production basis, interest expense decreased from $18.54 per BOE to $1.59 per BOE. The contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations for the six months ended December 31, 2016 was approximately $123.7 million, or $15.66 per BOE.

During the six months ended December 31, 2015, we repurchased certain of our unsecured notes in aggregate principal amounts as follows: $506.0 million of EGC 6.875% Senior Notes, $261.9 million of EGC 7.5% Senior Notes, $148.9 million of EGC 7.75% Senior Notes, $29.8 million of EPL 8.25% Senior Notes and $29.4 million of EGC 9.25% Senior Notes. We repurchased these notes in open market transactions at a total cost of approximately $213.1 million, and we recorded a gain on early extinguishment of debt of approximately $748.6 million, net of associated debt issuance costs and certain other expenses.

Reorganization Items

Since the filing of the Bankruptcy Petitions, the Predecessor has recorded $104.8 million in reorganization items ($90.6 million has been recorded in the six months ended December 31, 2016), which represent the direct and incremental costs of being in bankruptcy, and primarily consist of professional fees incurred from Petition Date through December 31, 2016. In addition, for the six months ended December 31, 2016, the Predecessor recorded $2,008.5 million gain on settlement of liabilities subject to compromise and $830.5 million gain on recording fresh start adjustments. Please see Note 4 — Fresh Start Accounting of Notes to Consolidated Financial Statements in this Form 10-K.

Income Tax Expense

We recorded no income tax expense or benefit for the six months ended December 31, 2016 and 2015, principally due to our inability to currently record any additional deferred tax assets. Please see Note 18 — Income Taxes of Notes to Consolidated Financial Statements in this Form 10-K.

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

	Predecessor
	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

	Predecessor
	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	)

(2) 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.

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

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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

	Predecessor
	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, net	$	(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 net capitalized costs 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

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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 GIGS Lease, 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 EGC 6.875% Senior Notes, $261.9 million of EGC 7.5% Senior Notes, $148.9 million of EGC 7.75% Senior Notes, $296.3 million of EPL 8.25% Senior Notes and $500.6 million of EGC 9.25% Senior Notes. 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 EXXI Ltd 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

From the filing of the Bankruptcy Petitions to June 30, 2016, we 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 18 — “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

	Predecessor
	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

	Predecessor
	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)

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	Predecessor
	Year Ended June 30,						Increase (Decrease)		Percent Increase (Decrease)			Revenue Increase (Decrease)
	2015			2014
												(In thousands)
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
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.

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Costs and expenses and other (income) expense

	Predecessor
	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
Other (income) expense
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 expense, net	$	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.

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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 the Second Lien Notes and the write-off of a portion of the deferred debt issue costs associated with our Prepetition 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 18 — “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. 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.

	Successor						Predecessor
	December 31, 2016						June 30, 2016						June 30, 2015
	Oil MMBbls		Natural Gas Bcf		MMBOE		Oil MMBbls		Natural Gas Bcf		MMBOE		Oil MMBbls		Natural Gas Bcf		MMBOE
Proved
Developed		66.5		113.6		85.4		66.3		121.1		86.6		94.0		188.0		125.3
Undeveloped		31.9		27.6		36.5		—		—		—		43.1		90.5		58.2
Total Proved		98.4		141.2		121.9		66.3		121.1		86.6		137.1		278.5		183.5

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Our proved reserves increased by 35.4 MMBOE or by approximately 41% from 86.6 MMBOE at June 30, 2016 to 121.9 MMBOE as of December 31, 2016. The increase was primarily due to:

• The booking of 36.5 MMBOE of proved undeveloped reserves. These reserves had been previously recorded by EXXI Ltd and then subsequently removed by it in the December 31, 2015 quarter due to the uncertainty regarding its ability to secure the required financing for developing such reserves prior to the Chapter 11 Cases; and

• Upward revisions of approximately 6.4 MMBOE of proved reserves resulting primarily from the extension in field life due to the addition of proved undeveloped reserves.

These were offset by:

• 7.9 MMBOE of production during the period.

Development of Proved Undeveloped Reserves

Due to the depressed commodity prices and EXXI Ltd’s lack of capital resources to develop its properties, the proved undeveloped oil and natural gas reserves no longer qualified as being proved as of December 31, 2015. As a result, EXXI Ltd removed all of our proved undeveloped oil and natural 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 were still economic at prices and costs applicable to SEC reserve reports at such date, 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 then current constraints on EXXI Ltd’s ability to fund development drilling.

Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million.

We update and approve our reserves development plan on an annual basis (updated at an interval of six months as of December 31, 2016), which includes our program to drill proved undeveloped locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value, cash flow and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total proved undeveloped reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors; including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves. As scheduled in our long range plan, substantially all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report.

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Our current proved undeveloped schedule is also subject to change due to external factors such as changes in commodity prices, the availability of capital, acquisitions, regulatory matters and the availability of drilling rigs that are capable of drilling in a given area. Senior management continuously monitors our development drilling plan to ensure that there is reasonable certainty of proceeding with our development plans and is required to approve any changes made to the existing long range plan and the related development plan. The following table presents the percentage of proved undeveloped reserves scheduled to be developed by fiscal year, in accordance with our long range plan.

	Successor
Year Ending December 31,	Percentage of Proved Undeveloped Reserves Scheduled to be Developed
2017		4.2	%
2018		26.7	%
2019		26.2	%
2020		22.2	%
2021		20.2	%
2022 – 2029		0.5	%
Total		100.0	%

Liquidity and Capital Resources

EXXI Ltd has historically funded its operations primarily through cash flows from operating activities, borrowings under Prepetition 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. Our primary use of cash flow is to fund capital expenditures used to develop our oil and gas properties. Our primary sources of liquidity are cash on hand and cash flows from operations. As of December 31, 2016, we had approximately $165.4 million of cash on hand and no available borrowing capacity under the Exit Facility.

In addition to the cash requirements necessary to fund ongoing operations, the Predecessor incurred significant professional fees and other costs in connection with the Chapter 11 Cases of approximately $90.6 million from July 1, 2016 through December 31, 2016 and approximately $14.2 million from Petition Date through June 30, 2016, which costs were classified as reorganization items on its consolidated statements of operations. Such fees have negatively impacted the level of cash on hand available to us upon the Predecessor’s emergence from bankruptcy. We do not expect to incur material professional reorganization expenses post-emergence.

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. For the calendar year 2017, the Company’s initial capital budget, excluding acquisitions but including plugging and abandonment is expected to be in the range of $140 million to $170 million, of which plugging and abandonment costs are expected to be in the range of $50 million to $70 million. The Company believes it has sufficient liquidity as of December 31, 2016, including approximately $165.4 million of cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements for operating and capital expenditures and for principal and interest payments on our outstanding debt. We expect to pay vendor, royalty and surety obligations on a go-forward basis according to the terms of our current contracts upon emergence from the Chapter 11 Cases.

Despite the liquidity provided by our existing cash on hand, our ability to maintain normal credit terms with our suppliers may become impaired even after our emergence from Chapter 11. 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.

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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 depends on the prevailing market prices for oil and natural gas, our 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. 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.

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.

Exit Facility

Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three year secured Exit Facility. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) the Exit Term Loan resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Debtors’ Prepetition Revolving Credit Facility of approximately $74 million and (ii) Exit Revolving Facility resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides, subject to the limitations noted below, for the making of revolving loans and the issuance of letters of credit.

The Exit Term Loan has a maturity of three years. Interest on the outstanding amount of the Exit Term Loan will accrue at an interest rate equal to either: (i) the Alternative Base Rate (as defined in the Exit Facility) plus 3.5% per annum or (ii) the one-month LIBO Rate (as defined in the Exit Facility) plus 4.5% per annum. Interest on the Exit Term Loan bearing interest at the Alternative Base Rate will be payable quarterly; interest on the Exit Term Loan bearing interest at the LIBO Rate will be payable monthly.

On the Emergence Date, the aggregate commitments under the Exit Revolving Facility were approximately $227.8 million all of which will be utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of ExxonMobil to secure certain plugging and abandonment obligations related to assets in the Gulf of Mexico. On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with ExxonMobil, it was agreed that subsequent to the Predecessor Company’s emergence from the Chapter 11 proceedings, the letters of credit issued in favor ExxonMobil would be reduced to $200 million from the existing amount of $225 million and currently documents are being formalized to effect such reduction. Each existing letter 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).

Following the Emergence Date, the commitments under the Exit Revolving Facility will be reduced by fifty percent of the amount of the aggregate reduction of $25 million of all letters of credit outstanding in favor of ExxonMobil. The remaining fifty percent or $12.5 million of such aggregate reduction will be available for borrowing as revolving loans subject to a maximum for all such loans of (i) $25 million prior to the date the borrowing base is initially determined and (ii) the borrowing base, on and after the date the borrowing base is initially determined. The borrowing base will be initially determined after June 30, 2017, and is redetermined semi-annually thereafter.

The Company must make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit if a reduction in revolving commitments would cause the revolving credit exposure to exceed the revolving credit commitments. On or after the determination of the borrowing base, the Company must also make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit not in favor of ExxonMobil if a borrowing base deficiency arises. For each fiscal quarter ending on and after March 31, 2018, if the Asset Coverage Ratio (as

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defined in the Exit Facility) is less than 1.50 to 1.00, the Company must make a mandatory prepayment of the Exit Term Loan equal to the lesser of (i) 7.5% of the aggregate outstanding principal amount of the Exit Term Loan on the Emergence Date or (ii) the then outstanding principal amount of the Exit Term Loan.

The Exit Revolving Facility has a maturity of three years. Interest on the outstanding amount of revolving loans borrowed under the Exit Revolving Facility will accrue at an interest rate equal to either (i) the Alternative Base Rate plus 3.5% per annum or (ii) the one, three or six month LIBO Rate plus 4.5% per annum. Interest on revolving loans that bear interest at the Alternative Base Rate will be payable quarterly; interest on revolving loans that bear interest at the LIBO Rate will be payable at the end of each interest period or, if an interest period exceeds three months, at the end of every three months. The stated amount of each letter of credit issued under the Exit Revolving Facility accrues fees at the rate of 4.5% per annum. There is an issuance fee of 0.25% per annum charged on the stated amount of each letter of credit issued after the Emergence Date.

Unused commitments under the Exit Revolving Facility will accrue a commitment fee of 0.50% payable quarterly in arrears.

The Exit Facility is guaranteed by substantially all of the wholly owned subsidiaries of the Company, subject to customary exceptions, and is secured by first priority security interests on substantially all assets of each Reorganized Debtor guarantor. Under the Exit Facility, the borrower will not declare or make a restricted payment, or make any deposit for any restricted payment. Restricted payments include declaration or payment of dividends.

The Exit Facility contains covenants and events of default customary for reserve-based lending facilities. In addition, for each fiscal quarter ending on and after March 31, 2018, the Company must maintain a Current Ratio (as defined in the Exit Facility) of no less than 1.00 to 1.00 and a First Lien Leverage Ratio (as defined in the Exit Facility) of no greater than 4.00 to 1.00 calculated on a trailing four quarter basis.

As of the Emergence Date, the Company met the requirement under the Exit Facility to have liquidity of at least $90 million. The Reorganized Debtors may use the proceeds of the Exit Facility for any permitted purpose, including satisfaction of ongoing working capital needs.

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, as such plan may be revised by the Proposed Plan Amendment, 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 and the BOEM have executed the Long-Term Plan, we have since submitted the Proposed Plan Amendment for the agency’s consideration and approval that would revise the Long-Term Plan. We can provide no assurance that we can continue in the future 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 BSEE or 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. 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 from time to time. 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.

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Capital Expenditures

For the six month transition period ended December 31, 2016, our capital expenditures excluding acquisitions but including plugging and abandonment obligations totaled approximately $47.8 million, of which approximately $22.3 million was spent on development of our core properties and $25.5 million on other assets. For the calendar year 2017, the Company’s initial capital budget, excluding acquisitions but including plugging and abandonment is expected to be in the range of $140 million to $170 million, of which plugging and abandonment costs are expected to be in the range of $50 million to $70 million. We believe that our capital resources from existing cash balances and anticipated cash flow from operating activities will be adequate to fund anticipated cash requirements for capital expenditures. 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 and the adequacy of our capital resources are difficult to predict and cannot be determined at this time. 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.

Cash Flows

The following table sets forth selected historical information from our statement of cash flows for the six months ended December 31, 2016 and 2015:

	Predecessor
	Six Months Ended December 31,
	2016			2015
				(Unaudited)
	(In thousands)
Net cash used in operating activities	$	(17,473	)	$	(89,924	)
Net cash provided by (used in) investing activities		11,706			(82,872	)
Net cash used in financing activities		(32,123	)		(258,162	)
Net decrease in cash and cash equivalents	$	(37,890	)	$	(430,958	)

Operating Activities

Net cash used in operating activities for the six months ended December 31, 2016 was $17.5 million as compared to $89.9 million used in operating activities for the six months ended December 31, 2015. The reduction in cash used in operating activities for the six months ended December 31, 2016 compared to cash used in operating activities for the six months ended December 31, 2015 was primarily due to no interest expense and a reduction of $22.0 million in cash outflows associated with operating assets and liabilities, partially offset by lower revenues due to a decline in production in the six months ended December 31, 2016.

Investing Activities

For the six months ended December 31, 2016, the cash provided by investing activities was $11.7 million as compared to cash outflows of $82.9 million for the six months ended December 31, 2015. The change in cash from investing activities during the six months ended December 31, 2016 compared to the six months ended December 31, 2015 was primarily due to the reduction in capital expenditures and withdrawals from restricted cash.

Financing Activities

Cash used in financing activities was $32.1 million for the six months ended December 31, 2016 as compared to cash used in financing activities of $258.2 million for the six months ended December 31, 2015. During the six months ended December 31, 2016, cash used in financing activities relates to $30.1 million paid towards reducing the amounts outstanding under Prepetition Credit Agreement and $2 million paid to settle EXXI Ltd’s 3% Senior Convertible Notes pursuant to the Plan. During the six months ended December 31, 2015, cash used in financing activities consists primarily of $225 million used in the repurchase

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of a portion of EXXI Ltd’s senior notes and payments on derivative instruments premium financing, $25.2 million used in repayment of debt assumed in the acquisition of all of the remaining equity interests of M21K, LLC (“M21K”) and dividends to preferred shareholders of $5.7 million.

The following table sets forth selected historical information from EXXI Ltd’s statement of cash flows for the years ended June 30, 2016, 2015 and 2014:

	Predecessor
	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 provides estimates of the timing of future payments that, as of December 31, 2016, we are obligated to make under our contractual obligations and commitments, other than hedging contracts. We expect to fund these contractual obligations with cash on hand, cash generated from operations and borrowings available under Exit Facility.

	Successor
	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)	$	78,497	$	4,268	$	74,229	$	—	$	—
Interest on long-term debt(1)		39,091		13,126		25,965		—		—

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	Successor
	Payments Due by Period
	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
	(In thousands)
Operating leases(2)		402,376		35,956		72,526		93,143		200,751
Total contractual obligations		519,964		53,350		172,720		93,143		200,751
Other Obligations
Asset retirement obligations(3)		753,364		56,601		322,213		91,927		282,623
Performance bond premiums(4)		5,700		5,700		—		—		—
Total obligations	$	1,279,028	$	115,651	$	494,933	$	185,070	$	483,374

(1) See Note 9 — “Long-Term Debt” of Notes to our Consolidated Financial Statements in this Form 10-K for details of our long-term debt. Interest on long-term includes fees relating to drawn letters of credit and unutilized line of credit.

(2) See Note 17 — “Commitments and Contingencies” of Notes to our Consolidated Financial Statements in this Form 10-K for discussion of these commitments.

(3) See Note 10 — “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 $388.2 million and letters of credit of $225 million which support our asset retirement obligations.

(4) See Note 17 — “Commitments and Contingencies” of Notes to our Consolidated Financial Statements in this Form 10-K. As of December 31, 2016, our total annual premium expense for supplemental bonding totaled $5.7 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 December 31, 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. 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

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financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, a gain on settlement of liabilities subject to compromise, a fair value adjustment gain and 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 Predecessor consolidated balance sheets in liabilities subject to compromise.

Fresh-start Accounting.  Upon emergence from bankruptcy, in accordance with ASC 852 related to fresh-start accounting, Reorganized EGC became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Convenience Date. The Convenience Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in the Predecessor historical consolidated balance sheets. The effects of the Plan and the application of fresh-start accounting are reflected in our consolidated balance sheet as of December 31, 2016 and the related adjustments thereto were recorded in the consolidated statement of operations of the Predecessor as reorganization items during the six month transition period ended December 31, 2016. Accordingly, Reorganized EGC’s consolidated financial statements as of and subsequent to December 31, 2016 are not and will not be comparable to the Predecessor consolidated financial statements prior to the Convenience Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on December 31, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

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 fresh start accounting; 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.

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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 or the costs are impaired, (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. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4-10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12-month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. For the three months ended September 30, 2016, EXXI Ltd’s ceiling test computation resulted in an impairment of its oil and natural gas properties of $86.8 million.

Due to the depressed commodity prices and EXXI Ltd’s lack of capital resources to develop its properties, all of its proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result, EXXI Ltd removed all of its 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 were still economic at prices and costs applicable to SEC reserve reports at such date, 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 then current constraints on EXXI Ltd’s ability to fund development drilling. Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million. As scheduled in our long range plan, substantially all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report.

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.

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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.

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. We use the current U.S. Federal statutory rate of 35% for measuring these deferred tax assets and liabilities, as adjusted for any applicable state taxes. For financial

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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, Depletion and Amortization (“DD&A”). Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Tax Code that allow capitalization of intangible drilling costs where management deems appropriate.

The tax bases of our assets and other tax attributes (such as NOLs) that are reflected in fresh-start accounting were heavily influenced by the Tax Attribute Reduction Rules of the Tax Code. As such, we were required to reduce our tax attributes on December 31, 2016 by approximately $2,600 million which equals the amount of CODI that was excluded from current taxation as a result of the indebtedness discharge from the Chapter 11 Cases. The remaining tax bases of our oil and natural gas properties are less than their respective book carrying values as determined in fresh-start accounting such that we have recorded a deferred tax liability for those properties. We have recorded a deferred tax asset for the asset retirement obligation (which has no tax basis and will be tax deductible or result in additional tax basis in assets when settled) and other items that exceed the deferred tax liability for oil and natural gas properties. Accordingly, we have recorded a valuation allowance of $174.5 million at December 31, 2016, which results in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of Predecessor losses) led to a conclusion that based upon the more-likely-than-not standard of the accounting literature; these deferred tax assets were unrecoverable.

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 asset, NOL and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized or adjusted in our consolidated financial statements. We have not recorded any reserves for uncertain income tax positions.

Share-Based Compensation.  Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an independent director or 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 December 31, 2016, we had no outstanding derivative instruments. 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

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adversely affect our revenues, cash flows and profitability. If we were to experience an extended depressed pricing environment, 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 EXXI Ltd’s lack of capital resources to develop its properties, all of its proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result, EXXI Ltd removed all of its 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 were still economic at prices and costs applicable to SEC reserve reports at such date, 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 then current constraints on EXXI Ltd’s 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.

In determination of the fair value of oil and natural gas properties under fresh start accounting, value was attributed to our proved reserves (including proved undeveloped, probable and possible reserves).

Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million.

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.

EXXI Ltd has 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. In February 2017, we entered into oil contracts (costless collars) benchmarked to Argus-LLS, to hedge 10,000 BPD of our production for the period from March 2017 to December 2017 with an floor price of $52.30 and an average ceiling price of $57.43.

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.

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 Exit 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. Following emergence from bankruptcy, we are no longer liable for interest on our fixed rate indebtedness (other than certain capital lease obligations). Therefore, we are exposed to interest rate risk for the indebtedness on which we are paying interest, specifically our Exit Facility. As of December 31, 2016, we had approximately $74 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 $0.1 million. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates.

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.

86

Item 8. Financial Statements and Supplementary Data

	Page
Management’s Report on Internal Control over Financial Reporting		88
Report of Independent Registered Public Accounting Firm		89
Report of Independent Registered Public Accounting Firm		90
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2016 (Successor) and June 30, 2016 and 2015 (Predecessor)		91
Consolidated Statements of Operations on December 31, 2016 (Successor) and for the Six Month Transition Period Ended December 31, 2016 and Years Ended June 30, 2016, 2015 and 2014 (Predecessor)		93
Consolidated Statements of Stockholders’ Equity (Deficit) on December 31, 2016 (Successor) and for the Six Month Transition Period Ended December 31, 2016 and Years Ended June 30, 2016, 2015 and 2014 (Predecessor)		94
Consolidated Statements of Cash Flows on December 31, 2016 (Successor) and for the Six Month Transition Period Ended December 31, 2016 and Years Ended June 30, 2016, 2015 and 2014 (Predecessor)		95
Notes to Consolidated Financial Statements		97

87

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 December 31, 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 December 31, 2016, our internal control over financial reporting was effective based on those criteria.

88

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Energy XXI Gulf Coast, Inc.
Houston, Texas

We have audited the accompanying consolidated balance sheet of Energy XXI Gulf Coast, Inc. and subsidiaries (“EGC” or the “Successor”) as of December 31, 2016 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the end-of-day December 31, 2016. We have also audited the accompanying consolidated balance sheets of the predecessor to EGC, Energy XXI Ltd and subsidiaries (the “Predecessor”), as of June 30, 2016 and 2015 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the six month transition period ended December 31, 2016 and for each of the two years in the period ended June 30, 2016. Successor and Predecessor are herein referred to as the “Company”. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the 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.

As discussed in Notes 3 and 4 to the consolidated financial statements, on December 13, 2016, the Bankruptcy Court entered an order confirming the plan of reorganization, which became effective on December 30, 2016. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with Accounting Standards Codification 852-10, Reorganizations, for the Successor as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods as described in Note 1.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Successor at December 31, 2016 and the results of its operations and its cash flow for the end-of-day December 31, 2016 and the financial position of the Predecessor at June 30, 2016 and 2015, and the results of its operations and its cash flows for the six month transition period ended December 31, 2016 and each of the two years in the period ended June 30, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP
 
Houston, Texas
February 22, 2017

89

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Energy XXI Gulf Coast, Inc.

We have audited the accompanying consolidated statements of operations, stockholders’ equity (deficit), and cash flows of the predecessor to Energy XXI Gulf Coast, Inc. and subsidiaries (the “Predecessor”) for the year ended June 30, 2014. The Predecessor’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements 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 the Predecessor for the year ended June 30, 2014, in conformity with accounting principles generally accepted in the United States of America.

/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 of the Predecessor for
the year ended June 30, 2015, as to which the date is September 29, 2015

90

ENERGY XXI GULF COAST, INC.
 
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share information)

	Successor		Predecessor
	December 31, 2016		June 30, 2016		June 30, 2015
ASSETS
Current Assets
Cash and cash equivalents	$	165,368	$	203,258	$	756,848
Accounts receivable, net
Oil and natural gas sales		68,143		63,644		100,243
Joint interest billings		5,600		8,770		12,433
Other		17,944		5,219		43,513
Prepaid expenses and other current assets		25,957		29,028		24,298
Restricted cash		32,337		38,965		9,359
Derivative financial instruments		—		—		22,229
Total Current Assets		315,349		348,884		968,923
Property and Equipment
Oil and natural gas properties, net – full cost method of accounting, including $376.1 million, $42.2 million and $436.4 million of unevaluated properties not being amortized at December 31, 2016, June 30, 2016 and 2015, respectively		1,097,479		603,155		3,570,759
Other property and equipment, net		18,807		17,610		21,820
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		1,116,286		620,765		3,592,579
Other Assets
Derivative financial instruments		—		—		3,898
Equity investments		—		—		10,835
Restricted cash		25,583		25,548		32,667
Other assets and debt issuance costs, net of accumulated amortization		28,244		30,237		81,927
Total Other Assets		53,827		55,785		129,327
Total Assets	$	1,485,462	$	1,025,434	$	4,690,829
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current Liabilities
Accounts payable	$	101,117	$	44,184	$	156,339
Accrued liabilities		63,660		40,428		155,306
Asset retirement obligations		56,601		71,717		33,286
Derivative financial instruments		—		—		2,661
Current maturities of long-term debt		4,268		99,836		11,395
Total Current Liabilities		225,646		256,165		358,987
Long-term debt, less current maturities		74,229		—		4,597,037
Asset retirement obligations		696,763		465,902		453,799
Derivative financial instruments		—		—		1,358
Other liabilities		14,481		21,304		8,370
Total Liabilities Not Subject to Compromise		1,011,119		743,371		5,419,551
Liabilities subject to compromise		—		2,936,148		—
Total Liabilities		1,011,119		3,679,519		5,419,551

 
 
See accompanying Notes to Consolidated Financial Statements

91

ENERGY XXI GULF COAST, INC.
 
CONSOLIDATED BALANCE SHEETS – (continued)
(In Thousands, except share information)

	Successor			Predecessor
	December 31, 2016			June 30, 2016			June 30, 2015
Commitments and Contingencies (Note 17)
Stockholders’ Equity (Deficit)
Predecessor Preferred stock, $0.001 par value, 7,500,000 shares authorized at June 30, 2016 and 2015
Predecessor 7.25% Convertible perpetual preferred stock, 3,000 shares issued and outstanding at June 30, 2016 and 2015		—			—			—
Predecessor 5.625% Convertible perpetual preferred stock, 661,992 and 812,759 shares issued and outstanding at June 30, 2016 and 2015, respectively		—			1			1
Successor Preferred stock, $0.01 par value, 10,000,000 shares authorized and no shares outstanding at December 31, 2016		—			—			—
Predecessor 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
Successor Common stock, $0.01 par value, 100,000,000 shares authorized and 33,211,594 shares		332			—			—
issued and outstanding at December 31, 2016		—			—			—
Predecessor Additional paid-in capital		—			1,845,684			1,843,918
Successor Additional paid-in capital		880,286			—			—
Accumulated deficit		(406,275	)		(4,500,258	)		(2,573,113	)
Total Stockholders’ Equity (Deficit)		474,343			(2,654,085	)		(728,722	)
Total Liabilities and Stockholders’ Equity (Deficit)	$	1,485,462		$	1,025,434		$	4,690,829

 
 
See accompanying Notes to Consolidated Financial Statements

92

ENERGY XXI GULF COAST, INC.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, except per share information)

	Successor			Predecessor
	On December 31,			Six Months Ended December 31,			Year Ended June 30,
	2016			2016			2016			2015			2014
Revenues
Oil sales	$	—		$	258,573		$	546,766		$	1,052,731		$	1,104,208
Natural gas sales		—			37,103			69,255			117,282			135,883
Gain (loss) on derivative financial instruments		—			—			90,506			235,439			(86,968	)
Total Revenues		—			295,676			706,527			1,405,452			1,153,123
Costs and Expenses
Lease operating		—			143,696			346,073			463,535			365,747
Production taxes		—			482			1,442			8,385			5,427
Gathering and transportation		—			19,551			55,925			21,144			23,532
Depreciation, depletion and amortization		—			60,626			339,516			705,521			414,026
Accretion of asset retirement obligations		—			38,973			64,690			50,081			30,183
Impairment of oil and natural gas properties		406,275			86,820			2,813,570			2,421,884			—
Goodwill impairment		—			—			—			329,293			—
General and administrative expense		—			27,557			102,736			116,500			96,402
Total Costs and Expenses		406,275			377,705			3,723,952			4,116,343			935,317
Operating Income (Loss)		(406,275	)		(82,029	)		(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		—			117			3,596			4,176			3,298
Gain on early extinguishment of debt		—			—			1,525,596			—			—
Interest expense		—			(12,580	)		(405,658	)		(323,308	)		(162,728	)
Total Other Income (Expense), net		—			(12,463	)		1,112,788			(336,297	)		(164,661	)
Income (Loss) Before Reorganization Items and Income Taxes		(406,275	)		(94,492	)		(1,904,637	)		(3,047,188	)		53,145
Reorganization items		—			2,748,395			(14,201	)		—			—
Income (Loss) Before Income Taxes		(406,275	)		2,653,903			(1,918,838	)		(3,047,188	)		53,145
Income Tax Expense (Benefit)		—			—			(87	)		(613,350	)		35,020
Net Income (Loss)		(406,275	)		2,653,903			(1,918,751	)		(2,433,838	)		18,125
Preferred Stock Dividends		—			—			8,394			11,468			11,489
Net Income (Loss) Attributable to Common Stockholders	$	(406,275	)	$	2,653,903		$	(1,927,145	)	$	(2,445,306	)	$	6,636
Earnings (Loss) per Share
Basic	$	(12.23	)	$	26.99		$	(20.11	)	$	(25.97	)	$	0.09
Diluted	$	(12.23	)	$	25.33		$	(20.11	)	$	(25.97	)	$	0.09
Weighted Average Number of Common Shares Outstanding
Basic		33,212			98,337			95,822			94,167			74,375
Diluted		33,212			104,787			95,822			94,167			74,445

 
 
See accompanying Notes to Consolidated Financial Statements

93

ENERGY XXI GULF COAST, INC.
 
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 (Predecessor)	$	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 (Predecessor)		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 (Predecessor)		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 (Predecessor)		1			—		97,824			488			—			—			1,845,684			(4,500,258	)		(2,654,085	)
Common stock issued, net of direct costs		—			—		3,146			16			—			—			(16	)		—			—
Common stock based compensation		—			—		—			—			—			—			183			—			183
Net Income		—			—		—			—			—			—			—			2,653,903			2,653,903
Balance, December 31, 2016 (Predecessor)		1			—		100,970			504			—			—			1,845,851			(1,846,355	)		1
Cancellation of Predecessor equity		(1	)		—		—			(504	)		—			—			(1,845,851	)		1,846,355			(1	)
Balance, December 31, 2016 (Predecessor)		—			—		100,970			—			—			—			—			—			—
Issuance of Successor common stock		—			—		33,212			332			—			—			872,230			—			872,562
Successor common stock warrants		—			—		—			—			—			—			8,056			—			8,056
Net Loss		—			—		—			—			—			—			—			(406,275	)		(406,275	)
Balance, December 31, 2016 (Successor)	$	—		$	—		33,212		$	332			—		$	—		$	880,286		$	(406,275	)	$	474,343

 
 
See accompanying Notes to Consolidated Financial Statements

94

ENERGY XXI GULF COAST, INC.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)

	Successor			Predecessor
	On December 31,			Six Months Ended December 31,			Year Ended June 30,
	2016			2016			2016			2015			2014
Cash Flows From Operating Activities
Net income (loss)	$	(406,275	)	$	2,653,903		$	(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		—			60,626			339,516			705,521			414,026
Impairment of oil and natural gas properties		406,275			86,820			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		—			38,973			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	)		—			—
Reorganization items		—			(2,838,963	)		—			—			—
Amortization and write-off of debt issuance costs, payment of interest in kind and other		—			5,025			138,473			23,247			13,774
Deferred rent		—			3,355			9,154			—			—
Provision for loss on accounts receivable		—			—			3,200			—			—
Stock-based compensation		—			183			1,336			4,124			6,711
Changes in operating assets and liabilities Accounts receivable		—			(16,545	)		42,742			51,284			63,283
Prepaid expenses and other assets		—			552			(24,438	)		48,062			6,019
Change in restricted cash		—			(25,157	)		—			—			—
Settlement of asset retirement obligations		—			(18,852	)		(78,273	)		(106,573	)		(57,391	)
Accounts payable and accrued liabilities		—			32,607			(62,187	)		(113,078	)		(55,536	)
Net Cash (Used in) Provided by Operating Activities		—			(17,473	)		(166,655	)		330,753			545,460
Cash Flows from Investing Activities
Acquisitions, net of cash		—			—			(2,797	)		(301	)		(849,641	)
Capital expenditures		—			(20,237	)		(111,884	)		(723,829	)		(788,676	)
Insurance payments received		—			—			8,251			3,920			1,983
Change in equity method investments		—			—			—			12,642			(34,294	)
Change in restricted cash		—			31,748			(22,136	)		(14,676	)		(325	)
Proceeds from the sale of properties		—			—			5,693			261,931			126,265
Other		—			195			(40	)		(135	)		113
Net Cash Used in Investing Activities		—			11,706			(122,913	)		(460,448	)		(1,544,575	)

 
 
See accompanying Notes to Consolidated Financial Statements

95

ENERGY XXI GULF COAST, INC.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS – (continued)
(In Thousands)

	Successor		Predecessor
	On December 31,		Six Months Ended December 31,			Year Ended June 30,
	2016		2016			2016			2015			2014
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		—		(32,088	)		(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		—		(35	)		(1,044	)		(66	)		—
Net Cash (Used in) Provided by Financing Activities		—		(32,123	)		(264,022	)		740,737			1,144,921
Net (Decrease) Increase in Cash and Cash Equivalents		—		(37,890	)		(553,590	)		611,042			145,806
Cash and Cash Equivalents, beginning of period		165,368		203,258			756,848			145,806			—
Cash and Cash Equivalents, end of period	$	165,368	$	165,368		$	203,258		$	756,848		$	145,806

 
 
See accompanying Notes to Consolidated Financial Statements

96

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization

Nature of Operations

Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation, was incorporated on February 7, 2006. Prior to emergence from the Chapter 11 Cases, EGC was an indirect wholly owned operating subsidiary of Energy XXI Ltd (“EXXI Ltd”). We are headquartered in Houston, Texas and have historically engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico Shelf, which is an area in less than 1,000 feet of water (“GoM Shelf”).

On April 14, 2016, EXXI Ltd, an exempt company incorporated under the laws of Bermuda and predecessor of the Reorganized EGC (as defined below) under this transition report for the six month transition period ended December 31, 2016, EGC, EPL Oil & Gas, Inc. (“EPL”), an indirect wholly-owned subsidiary of EXXI Ltd and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11.

On December 13, 2016, the Bankruptcy Court entered the Confirmation Order and on December 30, 2016, the Debtors emerged from bankruptcy.

In connection therewith, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to Energy XXI Gulf Coast, Inc. (the “Reorganized EGC”). In accordance with ASC 852, the Reorganized EGC applied fresh start accounting upon Predecessor’s emergence from bankruptcy and it evaluated transaction activity between the Emergence Date and December 31, 2016 and concluded an accounting convenience date of December 31, 2016 (the “Convenience Date”) was appropriate.

References to “Reorganized EGC,” “Company,” “we,” “our”, “Successor”, “Successor Company” or similar terms when used in reference to the period subsequent to the emergence from the bankruptcy refer to Reorganized EGC, the new Parent entity and successor issuer of EXXI Ltd pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). References in these consolidated financial statements to “EXXI Ltd,” “we,” “our”, “Predecessor”, “Predecessor Company” or similar terms when used in reference to the periods prior to the emergence from the bankruptcy refer to Energy XXI Ltd, the predecessor and former parent entity that will be dissolved upon the completion of the Bermuda Proceeding (as defined below). References in these consolidated financial statements to “EGC” refer to Energy XXI Gulf Coast, Inc. in the periods prior to the emergence from the bankruptcy during which it was the wholly-owned operating subsidiary of EXXI Ltd.

On February 7, 2017, the board of directors of the Company (the “Board”) adopted a resolution to change the Company's fiscal year end from June 30 to December 31. As a result, these financial statements are a transition report and include financial information for the transition period from July 1, 2016 through December 31, 2016. Subsequent to this report, our reports on Form 10-K will cover the calendar year, January 1 to December 31, which will be our fiscal year. Unless otherwise noted, all references to “years” in this Form 10-K refer to the twelve-month fiscal year, which, prior to July 1, 2016 ended on June 30, and, beginning after June 30, 2016, ends on December 31.

The audited financial statements of the Successor on December 31, 2016 reflect an impairment of our oil and natural gas properties of approximately $406.3 million which we recognized due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4-10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12-month average oil and gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting.

97

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization  – (continued)

Emergence from Chapter 11

On April 14, 2016 (the “Petition Date”), EXXI 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, 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”) were jointly administered under the caption “In re: Energy XXI Ltd, et al., Case No. 16-31928.” Thereafter until emergence, the Debtors 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. As a result of filing the Bankruptcy Petitions, EXXI Ltd’s common stock was delisted from the Nasdaq Global Select Market (the “NASDAQ”) and on May 19, 2016, its registration under Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) was withdrawn. As a result, EXXI Ltd’s common stock was deemed registered pursuant to Section 12(g) of the Exchange Act pursuant to Exchange Act Rule 12g-2(b).

Concurrently with the filing of the Bankruptcy Petitions, EXXI Ltd filed a petition seeking an order for liquidation of EXXI Ltd in the Supreme Court of Bermuda (the “Bermuda Court”) (the “Bermuda Proceeding”). On April 15, 2016, John C. McKenna was appointed as provisional liquidator (“Provisional Liquidator”) by the Bermuda Court. In light of the Plan and the emergence of EXXI Ltd, the Bermuda Court granted the entry into a winding up order formally placing EXXI Ltd in liquidation and confirming John C. McKenna as Provisional Liquidator. The liquidation is expected to be completed during the first half of 2017, and EXXI Ltd will, at such conclusion, be dissolved. During the pendency of the Bermuda Proceeding, EXXI Ltd has adopted a modified reporting program with respect to its reporting obligations under federal securities laws. EXXI Ltd does not intend to file periodic reports while the Bermuda Proceeding is pending, but will continue to file current reports on Form 8-K as required by federal securities laws.

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 Objection Deadline and Hearing Relating to Confirmation of the Plan and (C) Granting Related Relief. On July 18, 2016, the Debtors filed the solicitation version of the Debtors’ Third Amended Disclosure Statement (as amended, modified, or supplemented from time to time, the “Disclosure Statement”).

On November 21, 2016, the Debtors filed the Second Amended Proposed Joint Chapter 11 Plan of Reorganization (as amended, modified, or supplemented from time to time, the “Plan”) and the solicitation version of the Second Supplement to the Disclosure Statement Setting Forth Modifications to the Plan (as amended, modified, or supplemented from time to time, the “Disclosure Statement Supplement”).

On November 21, 2016, the Bankruptcy Court entered the Order (A) Approving the Adequacy of the Disclosure Statement Supplement to the Debtors’ Third Amended Disclosure Statement Setting Forth Modifications to the Debtors’ Plan and the Continued Solicitation of the Plan and (B) Granting Related Relief approving updated solicitation and tabulation procedures with respect to the Plan.

On December 13, 2016, the Bankruptcy Court entered an order (the “Confirmation Order”) pursuant to the Bankruptcy Code, which approved and confirmed the Plan as modified by the Confirmation Order.

98

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization  – (continued)

On December 30, 2016 (the “Emergence Date”), the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Company and the other reorganized Debtors (with the Company, the “Reorganized Debtors”) emerged from Chapter 11 Cases. In connection with the satisfaction of the conditions to effectiveness as set forth in the Confirmation Order and in the Plan, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to Reorganized EGC, as the new parent entity (the “Company”). Accordingly, Reorganized EGC succeeded to the entire business and operations previously consolidated for accounting purposes by EXXI Ltd.

Upon emergence from the Chapter 11 Cases, the Company adopted fresh start accounting in accordance with the provisions set forth in Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), because (i) the holders of existing voting shares of EXXI Ltd prior to its emergence received less than 50% of the voting shares of the Reorganized EGC outstanding following its emergence from bankruptcy and (ii) the reorganization value of EXXI Ltd’s assets immediately prior to confirmation of the Plan was less than its post-petition liabilities and allowed claims. Under ASC 852, the Company is considered a new legal entity for accounting purposes.

For reporting purposes, the pre-reorganization predecessor reflects the business that was transferred to the Reorganized EGC. The financial statements of the pre-reorganization predecessor are EXXI Ltd’s consolidated financial statements.

On January 6, 2017, the Company filed a Current Report on Form 8-K as the initial report of the Company to the Securities and Exchange Commission (the “SEC”) and as notice that the Company is the successor issuer to EXXI Ltd under Rule 12g-3 under the Exchange Act. As a result, the shares of common stock of the Company, par value $0.01 per share, are deemed to be registered under Section 12(g) of the Exchange Act. The Company is thereby deemed subject to the informational requirements of the Exchange Act, and the rules and regulations promulgated thereunder, and in accordance therewith will file reports and other information with the Commission.

Plan of Reorganization

In accordance with the Plan, the following significant transactions occurred:

Prepetition Notes

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the following notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled:

• 11.0% senior secured second lien notes due March 15, 2020 (the “Second Lien Notes”) issued pursuant to that certain Indenture, dated as of March 12, 2015, among EGC, the guarantors party thereto, and U.S. Bank, N.A., as trustee, and all amendments, supplements or modifications thereto and extensions thereof;

• 6.875% senior unsecured notes due March 15, 2024 (the “EGC 6.875 Senior Notes”) issued pursuant to that certain indenture, dated May 27, 2014, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof;

• 7.50% senior unsecured notes due December 15, 2021 (the “EGC 7.50% Senior Notes”) issued pursuant to that certain indenture, dated September 26, 2013, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof;

99

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization  – (continued)

• 7.75% senior unsecured notes due June 15, 2019 (the “EGC 7.75% Senior Notes”) issued pursuant to that certain indenture, dated February 25, 2011, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof;

• 9.25% senior unsecured notes due December 15, 2017 (the “EGC 9.25% Senior Notes,” and together with the EGC 6.875% Senior Notes, the EGC 7.50% Senior Notes, the EGC 7.75% Senior Notes and the “EGC Unsecured Notes”) issued pursuant to that certain indenture, dated December 17, 2010, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof;

• 8.25% senior unsecured notes due February 15, 2018 (the “EPL 8.25% Senior Notes”) issued pursuant to that certain indenture, dated as of February 14, 2011, by and EGC, the guarantors party thereto, and U.S. Bank National Association, as trustee, and all amendments, supplements or modifications thereto and extensions thereof; and

• 3.0% senior convertible notes due on December 15, 2018 (the “EXXI 3.0% Senior Convertible Notes”) issued pursuant to that certain indenture dated as of November 22, 2013 among EXXI Ltd and Wilmington Savings Fund Society, FSB, as trustee, and all amendments, supplements or modifications thereto and extensions thereof.

Prepetition Revolving Credit Facility and Exit Facility

On the Emergence Date, by operation of the Plan, all outstanding obligations under the Second Amended and Restated First Lien Credit Agreement (the “Prepetition Credit Agreement” or the “Prepetition Revolving Credit Facility”) and the related collateral agreements were cancelled and the credit agreements governing such obligations were cancelled.

Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three-year secured credit facility (the “Exit Facility”) with the prior lenders under the Prepetition Revolving Credit Facility. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount under the Prepetition Revolving Credit Facility of approximately $74 million plus accrued default interest, fees and expenses and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility, which provides for the making of revolving loans and the issuance of letters of credit. On the Emergence Date, the aggregate commitments under the Exit Revolving Facility were $227.8 million, all of which will be utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of Exxon Mobil Corporation (“ExxonMobil”) to secure certain plugging and abandonment obligations.

Equity Interests and Warrant Agreement

As a result of the Plan, there are no assets remaining in EXXI Ltd, and, under Bermuda law, shareholders (including preferred shareholders) of EXXI Ltd will receive no payments and all of its existing share-based compensation plans were also cancelled. EXXI Ltd will be dissolved at the conclusion of the Bermuda Proceeding, and as such, the shareholders will no longer have any interest in EXXI Ltd as a matter of Bermuda law.

On the Emergence Date, the Reorganized EGC entered into a warrant agreement (the “Warrant Agreement”) with Continental Stock Transfer & Trust Company, as Warrant Agent. Pursuant to the terms of the Plan, Reorganized EGC issued 2,119,889 warrants to certain prepetition noteholders pursuant to the Plan.

100

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization  – (continued)

On the Emergence Date, the Company issued 100% of its shares of common stock to certain of the Debtors’ creditors pursuant to the Plan. The Company issued (i) 27,897,739 shares of common stock, pro rata, to holders of the claims arising from the Second Lien Notes, (ii) 3,985,391 shares of common stock, pro rata, to holders of the claims arising from the EGC Unsecured Notes (the “EGC Unsecured Notes Claims”), (iii) 1,328,464 shares of common stock, pro rata, to holders of the claims arising from the EPL 8.25% Senior Notes (the “EPL Unsecured Notes Claims”), (iv) 1,271,933 warrants, pro rata, to holders of the EGC Unsecured Notes Claims; and (v) 847,956 warrants, pro rata, to holders of the EPL Unsecured Notes Claims. The Confirmation Order and Plan provide for the exemption of the offer and sale of the shares of the Company’s common stock and warrants (including shares of the Company’s common stock issuable upon the exercise thereof) from the registration requirements of the Securities Act of 1933 (the “Securities Act”) pursuant to Section 1145(a)(1) of the Bankruptcy Code. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied.

Long Term Incentive Plan and Schiller Employment and Consulting Agreement

As of the Emergence Date, the Company also entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the go-forward compensation for the Reorganized Debtors’ officers, directors, employees and consultants (“Service Providers”) and an employment agreement with our former Chief Executive Officer, John D. Schiller, Jr.

On February 2, 2017, John D. Schiller, Jr. resigned from his position as President and Chief Executive Officer (“CEO”) of the Company and also ceased to serve as a member of the Board. As a result, on February 2, 2017, the Board appointed Michael S. Reddin, the Company’s Chairman of the Board, to serve as the Company’s CEO and President on an interim basis. Mr. Reddin will continue to serve as Chairman of the Board. Because Mr. Reddin is now serving as both as Chairman of the Board and CEO, the Board has amended and restated the Company’s bylaws to provide for a Lead Independent Director and has appointed director James “Jay” W. Swent III to serve in that capacity. In order to eliminate the Board vacancy created by Mr. Schiller’s departure from the Board, the size of the Board was reduced from seven to six on February 2, 2017.

In connection with his termination of employment, the employment-related provisions of his Employment Agreement, dated as of December 30, 2016, with the Company (the “Schiller Employment Agreement”) were terminated as of February 2, 2017. Under the Schiller Employment Agreement, Mr. Schiller is entitled to receive the following benefits, subject to his entry into a waiver and release agreement (i) a lump-sum cash severance payment in the amount of $2 million, and (ii) reimbursement for the monthly cost of maintaining health benefits for Mr. Schiller and his spouse and eligible dependents as of the date of his termination for a period of 18 months to the extent Mr. Schiller elects COBRA continuation coverage, less applicable taxes and withholding. The $2 million cash severance payment is payable on April 3, 2017, the 60^th day after the termination date. On February 2, 2017, the Company entered into a consulting agreement (the “Schiller Consulting Agreement”) with Mr. Schiller, pursuant to which Mr. Schiller has agreed to serve as a special advisor to the Board during a transition period of up to six months. In consideration for those services, the Company has agreed to pay Mr. Schiller a consulting fee equal to $50,000 per month.

Amendments to Articles of Incorporation or Bylaws.

Pursuant to the Plan, on the Emergence Date, the Company’s certificate of incorporation and bylaws were amended and restated in their entirety. Each of the Company’s Second Amended and Restated Certificate of Incorporation (our “Certificate of Incorporation”) and second amended and restated bylaws became effective on the Emergence Date. Under the Certificate of Incorporation, the total number of all shares of capital stock

101

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization  – (continued)

that the Company is authorized to issue is 110 million shares, consisting of 100 million shares of the Company’s common stock, par value $0.01 per share, and 10 million shares of preferred stock, par value $0.01 per share.

In order to permit Mr. Reddin to be appointed CEO on an interim basis, the Board adopted the Third Amended and Restated Bylaws (the “Bylaws”) on February 2, 2017. Pursuant to the Bylaws, Section 4.1 was amended to provide that the positions of Chairman of the Board and Chief Executive Officer may be held by the same person only if (i) the two positions are held by the same person solely on an interim basis and (ii) the Board elects a Lead Independent Director for any period in which the two positions are held by the same person. Accordingly, the Bylaws added a new Section 3.8 to establish the position of Lead Independent Director and specified that position’s duties. The Bylaws provide that, during any period in which a Lead Independent Director is serving, the Lead Independent Director may, among other responsibilities, call and preside over all meetings of independent directors and, in the Chairman of the Board’s absence, preside over all meetings of the Company’s stockholders and of the Board.

After adopting the Bylaws, the Board appointed James “Jay” W. Swent III to serve as Lead Independent Director. Mr. Swent is an existing member of the Board, and will continue to serve as chairman of the Audit Committee of the Board. Mr. Swent has more than 35 years of global business and senior leadership experience.

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

Principles of Consolidation and Reporting.  The accompanying consolidated financial statements on December 31, 2016 include the accounts of Reorganized EGC and its wholly-owned subsidiaries and for prior periods, 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. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

For periods subsequent to filing the Bankruptcy Petitions, we have prepared the Predecessor’s consolidated financial statements in accordance with 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, a gain on settlement of liabilities subject to compromise, a fair value adjustment gain and 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 Predecessor consolidated balance sheets in liabilities subject to compromise.

Fresh-start Accounting.  Upon emergence from bankruptcy, in accordance with ASC 852 related to fresh-start accounting, Reorganized EGC became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Convenience Date. The Convenience Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in the Predecessor historical consolidated balance sheets. The effects of the Plan and the application of fresh-start accounting are reflected in our consolidated balance sheet as of December 31, 2016 and the related adjustments thereto were recorded in the consolidated statement of operations of the Predecessor as reorganization items during the six month transition period ended December 31, 2016. Accordingly, Reorganized EGC’s consolidated financial statements as of and subsequent to December 31, 2016 are not and will not be comparable to the Predecessor consolidated financial statements prior to the Convenience Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on

102

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

December 31, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

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 fresh start accounting; 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 specific identification method. As of December 31, 2016, there was no allowance for doubtful accounts. 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 or the costs are impaired, (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

103

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4-10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12-month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. For the three months ended September 30, 2016, EXXI Ltd’s ceiling test computation resulted in an impairment of its oil and natural gas properties of $86.8 million.

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 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

104

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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 6 — “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.

Debt Issuance Costs.  Costs incurred in connection with the issuance of long-term debt are presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability and are amortized to interest expense generally over the scheduled maturity of the debt utilizing the interest method. Costs incurred in connection with line-of-credit agreements are presented as an asset and subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings under the line-of-credit arrangement.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Common Stock.  Refers to either (i) Reorganized EGC’s common stock, par value $0.01 per share, as designated in its Second Amended and Restated Certificate of Incorporation for the period following emergence from the Chapter 11 or (ii) EXXI Ltd’s common stock, par value $0.005 per share, as designated in its Memorandum of Association. 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 December 31, 2016, 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 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 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 exploration and development activities for the six month transition period ended December 31, 2016 and for the years ended June 30, 2016, 2015 and 2014 was $7.8 million, $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 independent director or 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. We use the current U.S. Federal statutory rate of 35% for measuring these deferred tax assets and liabilities, as adjusted for any applicable state taxes. 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, Depletion and Amortization (“DD&A”). Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Tax Code that allow capitalization of intangible drilling costs where management deems appropriate.

The tax bases of our assets and other tax attributes (such as net operating loss (“NOL”) that are reflected in fresh-start accounting were heavily influenced by the Tax Attribute Reduction Rules of the Tax Code. As such, we were required to reduce our tax attributes on December 31, 2016 by approximately $2,600 million which equals the amount of cancellation of indebtedness income (“CODI”) that was excluded from current taxation as a result of the indebtedness discharge from the Chapter 11 Cases. The remaining tax bases of our oil and natural gas properties are less than their respective book carrying values as determined in fresh-start accounting such that we have recorded a deferred tax liability for those properties. We have recorded a deferred tax asset for the asset retirement obligation (which has no tax basis and will be tax deductible or result in additional tax basis in assets when settled) and other items that exceed the deferred tax liability for oil and natural gas properties. Accordingly, we have recorded a valuation allowance of $174.5 million at December 31, 2016, which results in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance at this date after an evaluation of all available

106

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

evidence (including our recent history of Predecessor losses) led to a conclusion that based upon the more-likely-than-not standard of the accounting literature; these deferred tax assets were unrecoverable.

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 asset, NOL and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized or adjusted in our consolidated financial statements. We have not recorded any reserves for uncertain income tax positions.

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 period. 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 Predecessor 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 in the initial stages of evaluating the effect of pending adoption of ASU 2014-09 on our financial position and results of operations and continue to evaluate the available transition methods.

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 amended 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. In the normal course of business, we enter into capital and operating lease agreements to support our operations. We are in the initial stages of evaluating the provisions of ASU 2016-02 to determine the quantitative effects it will have on our consolidated financial statements and related disclosures. We believe the adoption and implementation of this ASU will likely have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The new guidance in ASU 2016-15 is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The new standard is effective for public entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted provided that all of the amendments are adopted in the same period. The guidance requires application using a retrospective transition method. We have not yet determined the effect of this standard on our consolidated cash flows.

Note 3 — Chapter 11 Proceedings

On April 14, 2016, EXXI Ltd, EGC, EPL and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11. Following the filing, EXXI Ltd continued to operate its business as a debtor in possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

On December 13, 2016, the Bankruptcy Court entered the Confirmation Order, and on December 30, 2016, the Debtors emerged from bankruptcy.

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 represented EXXI Ltd’s allowed claims and its best estimate of claims expected to be allowed which were to be resolved as part of the bankruptcy proceedings. See Note 4 — “Fresh Start Accounting” on final determination on liabilities subject to compromise by the Bankruptcy Court. Liabilities subject to compromise include the following (in thousands):

	Predecessor
	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

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Chapter 11 Proceedings  – (continued)

Interest Expense

The Debtors 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 $176.5 million, representing interest expense from the Petition Date through December 31, 2016 with approximately $52.8 million, representing interest expense from the Petition Date through June 30, 2016.

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 November 29, 2016, the Debtors filed the Schedule of Rejected Executory Contracts and Unexpired Leases and the Modifications to Schedule of Assumed Executory Contracts and Unexpired Leases as part of the Plan Supplement [Docket No. 1713]. The assumption and rejection of the Debtors’ executory contracts and unexpired leases, as applicable, occurred on the effective date of the Plan in accordance with the terms of the Plan.

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 were required to file proofs of claim by August 22, 2016 (the “Bar Date”). As of February 3, 2017, 1,686 claims totaling approximately $43,359 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 as set forth in the Plan, 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 are being 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 has continued 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.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Fresh Start Accounting

On the Emergence Date, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Company and the other reorganized Debtors emerged from Chapter 11. In connection with the satisfaction of the conditions to effectiveness as set forth in the Confirmation Order and in the Plan, EXXI Ltd and EGC completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to Reorganized EGC. Accordingly, Reorganized EGC succeeded to the entire business and operations previously consolidated for accounting purposes at EXXI Ltd. Reorganized EGC applied fresh start accounting in accordance with the provisions set forth in ASC 852 on the Convenience Date, because (i) the holders of existing voting shares of EXXI Ltd prior to its emergence received less than 50% of the voting shares of the Reorganized EGC outstanding following its emergence from bankruptcy and (ii) the reorganization value of EXXI Ltd’s assets immediately prior to confirmation of the Plan was less than its post-petition liabilities and allowed claims. Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit and we allocated the reorganization value to our individual assets based on their estimated fair values. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, the consolidated financial statements on or after the Convenience Date will not be comparable with the consolidated financial statements prior to that date.

Reorganization Value.  Reorganization value represents the fair value of the Company’s total assets prior to the consideration of the liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. Under fresh start accounting, we allocated the reorganization value to our individual assets based on their estimated fair values.

Our reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s interest bearing long term debt and shareholders’ equity. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $600 million to $900 million. Based on the estimates and assumptions used in determining the enterprise value, as further discussed below, we estimated the enterprise value to be approximately $793.7 million. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections and applying standard valuation techniques, including risked net asset value analysis and public comparable company analyses.

Valuation of Oil and Gas Properties.  Our principal assets are our oil and gas properties, which we account for under the full cost method of accounting as described in Note 2 — “Summary of Significant Accounting Policies and Recent Accounting Pronouncements”. With the assistance of valuation experts, we determined the fair value of our oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Emergence Date.

Our internal reservoir engineers developed full cycle production models for all of our developed wells and identified undeveloped drilling locations within our leased acreage. The undeveloped locations were categorized based on varying levels of risk using industry standards. The proved locations were limited to wells expected to be drilled in the Company’s five year plan. The locations were then segregated into geographic areas. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange (“NYMEX”) four year forward prices for West Texas Intermediate (“WTI”) oil and Henry Hub natural gas with inflation adjustments applied to periods beyond four years. These prices were adjusted for typical differentials realized by us for location and product quality adjustments. Transportation cost estimates were based on agreements in place at the Emergence Date. Development and operating costs were based on our recent cost trends adjusted for inflation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Fresh Start Accounting  – (continued)

Risk factors were determined separately for each geographic area. Based on the geological characteristics of each area appropriate risk factors for each of the reserve categories were applied. We and our valuation experts considered production, geological and mechanical risk to determine the probability factor for each reserve category in each area.

The risk adjusted after tax cash flows were discounted at 11.1%. This discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. The after tax cash flow computations included utilization of the Company’s unamortized tax basis in the properties as of the Emergence Date. Plugging and abandonment costs were included in the cash flow projections for undeveloped reserves but were excluded for developed reserves since the fair value of this liability was determined separately and included in the Emergence Date liabilities reported on the December 31, 2016 balance sheet.

From this analysis we concluded the fair value of our proved reserves was $1,127.6 million, the value of our probable reserves was $295.3 million and the value of our possible reserves was $80.8 million as of the Convenience Date. The value of probable and possible reserves was classified as unevaluated costs. We also reviewed our undeveloped leasehold acreage and concluded that the fair value of our probable and possible reserves appropriately captured the fair value of our undeveloped leasehold acreage. Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment.

The following table reconciles the enterprise value to the estimated fair value of the Successor Company's common stock as of the Convenience Date (in thousands):

	December 31, 2016
Enterprise Value	$	793,747
Add: Cash and cash equivalents		165,368
Less: Fair value of debt		(78,497	)
Fair Value of Successor common stock and warrants		880,618
Less: Fair value of warrants		(8,056	)
Fair Value of Successor common stock	$	872,562

Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three-year secured credit facility (the “Exit Facility”). The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Prepetition Revolving Credit Facility of approximately $74 million and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides, subject to the limitations noted below, for the making of revolving loans and the issuance of letters of credit.

On the Emergence Date, the Company entered into a Warrant Agreement with Continental Stock Transfer & Trust Company, as Warrant Agent. On the Emergence Date, pursuant to the terms of the Plan, the Company issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims. The warrants are exercisable from the date of the Warrant Agreement until December 30, 2021 (the “Expiration Date”). The warrants are initially exercisable for one share of the Company’s common stock per warrant (such rate, as adjusted pursuant to the Warrant Agreement, being the “Warrant Exercise Shares”) at an initial exercise price of $43.66 (the “Exercise Price”). The Warrant Exercise Shares and Exercise Price

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Fresh Start Accounting  – (continued)

are subject to customary anti-dilution adjustments. No adjustments to the applicable Exercise Price or Warrant Exercise Shares are required unless the cumulative adjustments required would result in an increase or decrease of at least 1.0% in the applicable Exercise Price or the Warrant Exercise Shares. Additionally, if an adjustment in Exercise Price would reduce the Exercise Price to an amount below par value of the common stock, then such adjustment in Exercise Price will reduce the Exercise Price to the par value of the common stock. The fair value of the warrants was $3.80 per warrant. A Black-Scholes pricing model with the following assumptions was used in determining the fair value:

The following table reconciles the enterprise value to the estimated reorganization value as of the Emergence Date (in thousands):

	December 31, 2016
Enterprise Value	$	793,747
Add: Cash and cash equivalents		165,368
Add: Other working capital liabilities		164,777
Add: Other long-term liabilities		14,481
Add: Asset retirement obligation		753,364
Reorganization value of Successor assets	$	1,891,737

Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.

Consolidated Balance Sheet

The adjustments set forth in the following consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”), fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). On the Convenience Date, subsequent to the restructuring adjustments and fair value adjustments, we recorded an impairment of our oil and natural gas properties of approximately $406.3 million, primarily due to pricing differences between the 12-month average oil and gas prices used in the ceiling test and the forward strip prices used to estimate the fresh start fair value of oil and gas properties of the Company (reflected in the column “Impairment”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Fresh Start Accounting  – (continued)

The following table reflects the reorganization and application of ASC 852 and the Convenience Date ceiling test impairment on our consolidated balance sheet as of December 31, 2016 (in thousands):

	As of December 31, 2016
	Predecessor Company		Reorganization Adjustments					Fresh-Start Adjustments					Successor Company before Impairment		Impairment			Successor Company
ASSETS
Current Assets
Cash and cash equivalents	$	164,817	$	551			(1)	$	—				$	165,368	$	—		$	165,368
Accounts receivable, net									—					—
Oil and natural gas sales		68,143		—					—					68,143		—			68,143
Joint interest billings		5,600		—					—					5,600		—			5,600
Other		18,909		(965	)		(3)		—					17,944		—			17,944
Prepaid expenses and other current assets		54,100		(26,260	)		(2)		(1,883	)		(10)		25,957		—			25,957
Restricted cash		32,888		(551	)		(1)		—					32,337		—			32,337
Total Current Assets		344,457		(27,225	)				(1,883	)				315,349		—			315,349
Property and Equipment
Oil and natural gas properties, net		500,114		—					1,003,640			(11)		1,503,754		(406,275	)		1,097,479
Other property and equipment, net		15,049		—					3,758			(12)		18,807		—			18,807
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		515,163		—					1,007,398					1,522,561		(406,275	)		1,116,286
Other Assets
Restricted cash		25,583		—					—					25,583		—			25,583
Other assets		30,174		—					(1,930	)		(13)		28,244		—			28,244
Total Other Assets		55,757		—					(1,930	)				53,827		—			53,827
Total Assets	$	915,377	$	(27,225	)			$	1,003,585				$	1,891,737	$	(406,275	)	$	1,485,462
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current Liabilities
Accounts payable	$	67,876	$	33,241			(3)	$	—				$	101,117	$	—		$	101,117
Accrued liabilities		48,500		15,160			(3)(4)		—					63,660		—			63,660
Asset retirement obligations		58,537		—					(1,936	)		(14)		56,601		—			56,601
Current maturities of long-term debt		74,046		(69,778	)		(5)		—					4,268		—			4,268
Total Current Liabilities		248,959		(21,377	)				(1,936	)				225,646		—			225,646
Long-term debt, less current maturities		—		74,229			(5)		—					74,229		—			74,229
Asset retirement obligations		509,187		—					187,576			(14)		696,763		—			696,763
Other liabilities		24,662		2,345			(3)		(12,526	)		(15)		14,481		—			14,481
Total Liabilities Not Subject to Compromise		782,808		55,197					173,114					1,011,119		—			1,011,119
Liabilities subject to compromise		2,934,619		(2,934,619	)		(6)		—					—		—			—
Total Liabilities		3,717,427		(2,879,422	)				173,114					1,011,119		—			1,011,119

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Fresh Start Accounting  – (continued)

	As of December 31, 2016
	Predecessor Company			Reorganization Adjustments					Fresh-Start Adjustments				Successor Company before Impairment		Impairment			Successor Company
Stockholders’ Equity (Deficit)
Preferred stock (Predecessor)
7.25% Convertible perpetual preferred stock (Predecessor)		—			—					—				—		—			—
5.625% Convertible perpetual preferred stock (Predecessor)		—			—					—				—		—			—
Common stock (Predecessor)		504			(504	)		(7)		—				—		—			—
Common stock (Successor)		—			332			(8)		—				332		—			332
Additional paid-in capital (Predecessor)		1,845,851			(1,845,851	)		(7)		—				—		—			—
Additional paid-in capital (Successor)		—			880,286			(8)		—				880,286		—			880,286
Accumulated deficit		(4,648,405	)		3,817,934			(9)		830,471		(16)		—		(406,275	)		(406,275	)
Total Stockholders’ Equity (Deficit)		(2,802,050	)		2,852,197					830,471				880,618		(406,275	)		474,343
Total Liabilities and Stockholders’ Equity (Deficit)	$	915,377		$	(27,225	)			$	1,003,585			$	1,891,737	$	(406,275	)	$	1,485,462

Reorganization Adjustments

(1) Reflects the reclassification of the utility deposit from restricted cash to cash and cash equivalents.

(2) Represents cash payments made prior to the Convenience Date to the following parties in accordance with the Plan (i) approximately $11.2 million to the Plan support parties of the EGC Unsecured Noteholders for professional fees, (ii) approximately $9.6 million to the Plan support parties of the EPL Unsecured Noteholders for professional fees, (iii) approximately $2 million for EXXI Ltd’s 3.0% Senior Convertible Notes Trustee, and (iv) approximately $3.5 million for success fees paid to EXXI Ltd’s restructuring advisors. The amounts were recorded as prepaid expenses on the Emergence Date and subsequently reflected as effects of the Plan on the Convenience Date.

(3) Represents reinstated claims that were reclassified from liabilities subject to compromise at Emergence Date and will be settled in cash. Of the approximate $3.4 million claims reinstated to accrued liabilities, approximately $1.0 million of the reinstated claims were applied against other receivables in accordance with the right of offset approved by the Bankruptcy Court and the remaining approximately $2.4 million of reinstated claims were reclassified to accrued liabilities.

(4) Represents success fee accrual of $11 million payable to restructuring advisors and a professional fee accrual of $1.7 million payable to the Plan support parties of EGC and EPL Unsecured Noteholders.

(5) Represents the reclassification of the revolving credit facility and the reinstated claims related to 4.14% promissory note and capital lease obligations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Fresh Start Accounting  – (continued)

(6) Liabilities subject to compromise were settled as noted below (in thousands):

	On December 31, 2016
Predecessor 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		4,001
Capital lease obligations		450
Total debt		2,763,739
Accounts payable		37,424
Accrued liabilities		133,456
Total liabilities subject to compromise		2,934,619
Fair value of equity and warrants issued per the Plan		(880,618	)
Fair value of reinstated accounts payable and accrued liabilities to be settled in cash		(43,509	)
Cash payment for 3.0% Senior Convertible Notes		(2,000	)
Gain on settlement of liabilities subject to compromise	$	2,008,492

(7) Reflects the cancellation of EXXI Ltd’s equity.

(8) Represents the issuance of Successor equity. The Successor Company issued a total of 33,211,594 shares of its common stock, of which 27,897,739 shares of common stock were issued to the Second Lien Holders, 3,985,391 shares of common stock was issued to the holders of EGC Unsecured Notes and 1,328,464 shares of common stock was issued to the EPL Unsecured Notes. The Successor equity is subject to dilution by exercise of 1,271,933 warrants issued to the holders of EGC Unsecured Noteholders and 847,956 warrants issued the EPL Unsecured Noteholders for 2,119,889 shares of common stock with an initial exercise price of $43.66. The fair value of the warrants was estimated at $8.1 million or $3.80 per warrant, using the Black-Scholes Option pricing valuation model.

(9) The cumulative impact of the reorganization adjustments is as below (in thousands):

	December 31, 2016
Gain on settlement of liabilities subject to compromise	$	2,008,492
Cancellation of EXXI Ltd equity		1,846,355
Accrual of success fee		(12,653	)
Payments made of plan support parties		(24,260	)
Net impact to accumulated deficit	$	3,817,934

Fresh Start Adjustments

(10) Represents the write off of the unamortized deferred financing costs related to the Prepetition Credit Facility.

(11) In estimating the fair value of its oil and natural gas properties, the Company used a combination of the income and market approaches. For purposes of estimating fair value of the Company's proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company's reserves, risked by reserve category and discounted using a weighted average cost of capital of 11.1%. Weighted average commodity prices utilized in the

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Note 4 — Fresh Start Accounting  – (continued)

determination of the fair value of oil and natural gas properties were $60.37 per barrel of oil, $3.02 per MMBtu of natural gas and $25.36 per barrel of NGL, after adjusting for regional pricing differentials. The proved reserve locations were limited to wells expected to be drilled in the Company's five year development plan. Base pricing was derived from strip prices on the December 30, 2016 and subsequently increased at an inflation escalation factor of 2.0% after the fourth year.

(12) In estimating the fair value of the other property and equipment, the Company primarily employed a combination of cost and market approaches. These assets were primarily evaluated using a replacement cost methodology and also obtaining market-based pricing indicators for certain assets which had active secondary markets.

(13) Represents the removal of catering business goodwill and deferred lease expenses.

(14) Represents the adjustment of asset retirement obligations to fair value using estimated plugging and abandonment costs as of December 31, 2016, adjusted for inflation using a rate of 2% and then discounted at the credit-adjusted risk free rate of 6.5%. The fair value of asset retirement obligation was estimated at $753.4 million.

(15) Represents the removal of deferred rent liabilities.

(16) Represents the cumulative effects of the fresh-start accounting adjustments.

Reorganization Items

Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as “Reorganization items” in the consolidated statements of operations. The following table summarizes reorganization items (in thousands):

	Predecessor
	Six Months Ended December 31, 2016			Year Ended June 30, 2016
Gain on settlement of liabilities subject to compromise	$	2,008,492		$	—
Fresh start adjustments		830,471			—
Reorganization legal and professional fees and expenses		(90,568	)		(14,201	)
Gain (loss) on reorganization items	$	2,748,395		$	(14,201	)

Note 5 — 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 EXXI Ltd owned 20% interest, and Energy XXI GOM, LLC, an indirect wholly owned subsidiary of EXXI Ltd, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Acquisitions and Dispositions  – (continued)

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 8 — 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 EXXI Ltd as the acquirer. EPL became a wholly owned subsidiary of EGC.

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 EXXI Ltd common stock (“Stock Election”) or a combination of $25.35 in cash and 0.584 of a share of EXXI Ltd 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 EXXI Ltd common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of EXXI Ltd 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 EXXI Ltd 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		EXXI Ltd Stock		Cash Paid		EXXI Ltd Stock Issued		EXXI Ltd Stock Price on June 3, 2014		Cash Value of EXXI Ltd 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — 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 6 — “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 March and 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 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 was not deductible for income tax purposes.

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.

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Note 5 — Acquisitions and Dispositions  – (continued)

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 6 — “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 EXXI Ltd 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 EXXI Ltd common stockholders		(56,722	)
Net loss per share available to EXXI Ltd 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.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Acquisitions and Dispositions  – (continued)

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.

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 17 — “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 $6.4 million. The final settlement occured in January 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — 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 was $0.8 million of goodwill associated with the acquisition of a catering business on August 21, 2015. On the Convenience Date, there was no goodwill after recording the effect of the consummation of the transactions contemplated by the Plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7 — Property and Equipment

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

	Successor			Predecessor
	December 31, 2016			June 30, 2016			June 30, 2015
Oil and gas properties
Proved properties	$	1,127,616		$	9,817,456		$	9,243,737
Less: accumulated depreciation, depletion, amortization and impairment		(406,275	)		(9,256,513	)		(6,109,335	)
Proved properties, net		721,341			560,943			3,134,402
Unevaluated properties		376,138			42,212			436,357
Oil and gas properties, net		1,097,479			603,155			3,570,759
Other property and equipment		18,807			44,272			45,941
Less: accumulated depreciation		—			(26,662	)		(24,121	)
Other property and equipment, net		18,807			17,610			21,820
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	1,116,286		$	620,765		$	3,592,579

See Note 4 — “Fresh Start Accounting” for the methodology and assumptions used in arriving at fair value fresh start adjustments on the Convenience Date.

Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million. As scheduled in our long range plan, substantially all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report.

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 the costs are impaired, (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.

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 capitalized costs 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 our oil and natural gas properties to the amount of the discounted cash flows. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4-10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12-month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. If the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7 — Property and Equipment  – (continued)

current low commodity price environment or downward trend in oil and natural gas prices continues, we may 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.

For the six month transition period ended December 31, 2016, EXXI Ltd’s ceiling test computation resulted in an impairment of its oil and natural gas properties of $86.8 million and for the years ended June 30, 2016 and 2015, the impairments totaled $2,813.6 million and $2,421.9 million, respectively.

Due to the depressed commodity prices and EXXI Ltd’s lack of capital resources to develop its properties, all of its proved undeveloped oil and gas reserves no longer qualified as being proved as of December 31, 2015. As a result, EXXI Ltd removed all of its 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 were still economic at prices and costs applicable to SEC reserve reports at such date, 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 then current constraints on EXXI Ltd’s ability to fund development drilling. In addition, 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.

Note 8 — 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 15 — “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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Long-Term Debt

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

	Successor		Predecessor
	December 31,		June 30,
	2016		2016		2015
Prepetition Revolving Credit Facility(2)	$	—	$	99,836	$	150,000
Exit Facility		73,996		—		—
11.0% Senior Secured Second Lien Notes due 2020(2)		—		1,450,000		1,450,000
8.25% Senior Notes due 2018(2)		—		213,677		510,000
6.875% Senior Notes due 2024(2)		—		143,993		650,000
3.0% Senior Convertible Notes due 2018(2)		—		363,018		400,000
7.5% Senior Notes due 2021(2)		—		238,071		500,000
7.75% Senior Notes due 2019(2)		—		101,077		250,000
9.25% Senior Notes due 2017(2)		—		249,452		750,000
4.14% Promissory Note due 2017		4,001		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		500		714		869
Total debt		78,497		2,863,844		4,608,432
Less: current maturities		4,268		99,836		11,395
Less: liabilities subject to compromise (see Note 3)		—		2,764,008		—
Total long-term debt	$	74,229	$	—	$	4,597,037

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

(2) In accordance with the Plan, on the Emergence Date, all outstanding obligations under these notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.

Maturities of long-term debt as of December 31, 2016 are as follows (in thousands)

Twelve Months Ending December 31,
2017	$	4,268
2018		233
2019		73,996
2020		—
2021		—
Thereafter		—
	$	78,497

During the year ended June 30, 2016, our Predecessor repurchased certain of its 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”). Our Predecessor repurchased these notes in open market transactions at a total cost of approximately

124

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Long-Term Debt  – (continued)

$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 notes repurchased in February 2016, 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 were cancelled at June 30, 2016 and the remaining EGC and EPL senior notes held by EGC were cancelled on December 19, 2016. In addition, in March 2016 certain bondholders holding $37 million in face value of Predecessor’s 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 Prepetition 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 were automatically stayed as a result of Chapter 11. Accordingly, all of EXXI Ltd’s outstanding indebtedness was classified as current in the consolidated balance sheet and it 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 Prepetition Revolving Credit Facility, EXXI Ltd accelerated the amortization of the remaining debt issuance costs related to its outstanding indebtedness, fully amortizing those costs as of March 31, 2016. EXXI Ltd continued to accrue interest on the Prepetition Revolving Credit Facility subsequent to the Petition Date until the Convenience Date. However, for all of its other indebtedness, in accordance with ASC 852, Reorganizations, it accrued interest only up to the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the Predecessor consolidated statements of operations was approximately $176.5 million, representing interest expense from the Petition Date through the Emergence Date, of which $123.7 pertained to the six month transition period ended December 31, 2016.

Exit Facility

Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three year secured Exit Facility. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) the Exit Term Loan resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Debtors’ Prepetition Revolving Credit Facility of approximately $74 million and (ii) Exit Revolving Facility resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides, subject to the limitations noted below, for the making of revolving loans and the issuance of letters of credit.

The Exit Term Loan has a maturity of three years. Interest on the outstanding amount of the Exit Term Loan will accrue at an interest rate equal to either: (i) the Alternative Base Rate (as defined in the Exit Facility) plus 3.5% per annum or (ii) the one-month LIBO Rate (as defined in the Exit Facility) plus 4.5% per annum. Interest on the Exit Term Loan bearing interest at the Alternative Base Rate will be payable quarterly; interest on the Exit Term Loan bearing interest at the LIBO Rate will be payable monthly.

On the Emergence Date, the aggregate commitments under the Exit Revolving Facility were approximately $227.8 million all of which will be utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of ExxonMobil to secure certain plugging and abandonment obligations related to assets in the Gulf of Mexico. On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with ExxonMobil, it was agreed that subsequent to the Predecessor Company’s emergence from the Chapter 11 proceedings, the letters of credit issued in favor

125

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Long-Term Debt  – (continued)

ExxonMobil would be reduced to $200 million from the existing amount of $225 million and currently documents are being formalized to effect such reduction. Each existing letter 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).

Following the Emergence Date, the commitments under the Exit Revolving Facility will be reduced by fifty percent of the amount of the aggregate reduction of $25 million of all letters of credit outstanding in favor of ExxonMobil. The remaining fifty percent or $12.5 million of such aggregate reduction will be available for borrowing as revolving loans subject to a maximum for all such loans of (i) $25 million prior to the date the borrowing base is initially determined and (ii) the borrowing base, on and after the date the borrowing base is initially determined. The borrowing base will be initially determined after June 30, 2017, and is redetermined semi-annually thereafter.

The Company must make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit if a reduction in revolving commitments would cause the revolving credit exposure to exceed the revolving credit commitments. On or after the determination of the borrowing base, the Company must also make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit not in favor of ExxonMobil if a borrowing base deficiency arises. For each fiscal quarter ending on and after March 31, 2018, if the Asset Coverage Ratio (as defined in the Exit Facility) is less than 1.50 to 1.00, the Company must make a mandatory prepayment of the Exit Term Loan equal to the lesser of (i) 7.5% of the aggregate outstanding principal amount of the Exit Term Loan on the Emergence Date or (ii) the then outstanding principal amount of the Exit Term Loan.

The Exit Revolving Facility has a maturity of three years. Interest on the outstanding amount of revolving loans borrowed under the Exit Revolving Facility will accrue at an interest rate equal to either (i) the Alternative Base Rate plus 3.5% per annum or (ii) the one, three or six month LIBO Rate plus 4.5% per annum. Interest on revolving loans that bear interest at the Alternative Base Rate will be payable quarterly; interest on revolving loans that bear interest at the LIBO Rate will be payable at the end of each interest period or, if an interest period exceeds three months, at the end of every three months. The stated amount of each letter of credit issued under the Exit Revolving Facility accrues fees at the rate of 4.5% per annum. There is an issuance fee of 0.25% per annum charged on the stated amount of each letter of credit issued after the Emergence Date.

Unused commitments under the Exit Revolving Facility will accrue a commitment fee of 0.50% payable quarterly in arrears.

The Exit Facility is guaranteed by substantially all of the wholly owned subsidiaries of the Company, subject to customary exceptions, and is secured by first priority security interests on substantially all assets of each Reorganized Debtor guarantor. Under the Exit Facility, the borrower will not declare or make a restricted payment, or make any deposit for any restricted payment. Restricted payments include declaration or payment of dividends.

The Exit Facility contains covenants and events of default customary for reserve-based lending facilities. In addition, for each fiscal quarter ending on and after March 31, 2018, the Company must maintain a Current Ratio (as defined in the Exit Facility) of no less than 1.00 to 1.00 and a First Lien Leverage Ratio (as defined in the Exit Facility) of no greater than 4.00 to 1.00 calculated on a trailing four quarter basis.

As of the Emergence Date, the Company met the requirement under the Exit Facility to have liquidity of at least $90 million. The Reorganized Debtors may use the proceeds of the Exit Facility for any permitted purpose, including satisfaction of ongoing working capital needs.

As of December 31, 2016, we had approximately $74 million in borrowings and $227.8 million in letters of credit issued under the Exit Facility.

126

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Long-Term Debt  – (continued)

Prepetition Revolving Credit Facility

The Prepetition Revolving Credit Facility was entered into by EGC in May 2011. The Prepetition Revolving Credit Facility had a maximum facility amount and borrowing base of $327.2 million, of which such amount $99.4 million was the borrowing base under the sub-facility established for EPL prior to the Chapter 11 Cases. Borrowings under the Prepetition Revolving Credit Facility were limited to a borrowing base based on oil and natural gas reserve values. The scheduled date of maturity of the Prepetition Credit Agreement was April 9, 2018. As a result of the filing of the Bankruptcy Petitions, the highest of the margins applied and default interest was accruing under the facility through an additional 2.00% payment of interest in kind (“PIK”) interest. PIK interest totaling $4.7 million was accrued from the Petition Date through December 31, 2016.

Following the modification to the cash collateral order, which was approved by the Bankruptcy Court on October 24, 2016, approximately $30.1 million of restricted cash maintained by EGC related to our Prepetition Credit Agreement was withdrawn on October 25, 2016 and applied to permanently reduce the amount outstanding under its Prepetition Credit Agreement to $69.3 million, thereby resulting in a further reduction to the maximum facility amount and borrowing base to $297.1 million.

On the Emergence Date, by operation of the Plan, all outstanding obligations under the Prepetition Revolving Credit Facility and the related collateral agreements were cancelled and the credit agreements governing such obligations were cancelled.

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 were not registered under the Securities Act or the securities laws of any other jurisdiction. The Second Lien Notes bore 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 were 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 secured the Prepetition Revolving Credit Facility. The liens securing the Second Lien Notes and the related guarantees were contractually subordinated to the liens on such assets securing our Prepetition 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 were fully and unconditionally guaranteed on a senior basis by the Guarantors.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Long-Term Debt  – (continued)

The 2015 Indenture restricted 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 were subject to a number of important exceptions and qualifications.

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the Second Lien Notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.

8.25% Senior Notes Due 2018

On June 3, 2014, EGC assumed the 8.25% Senior Notes in the EPL Acquisition which consisted 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 were 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 were to 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 were callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the 8.25% Senior Notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.

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.

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the 6.875% Senior Notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.

3.0% Senior Convertible Notes due 2018

On November 18, 2013, EXXI 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 were convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the election of EXXI 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

128

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Long-Term Debt  – (continued)

$40.40 per share of common stock). The conversion rate, and accordingly the conversion price, were permitted to 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 were permitted to 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 EXXI Ltd’s 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 EXXI Ltd common stock multiplied by the then current conversion rate. Accordingly, certain bondholders holding $37 million in face value of the 3.0% Senior Convertible Notes requested conversion into shares of EXXI Ltd common stock. Upon conversion, EXXI Ltd elected to issue shares of its 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.

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the 3.0% Senior Notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.

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.

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the 7.5% Senior Notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.

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.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Long-Term Debt  – (continued)

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the 7.75% Senior Notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.

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.

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the 9.25% Senior Notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.

4.14% Promissory Note

In September 2012, the Predecessor entered into a promissory note of $5.5 million to acquire other property and equipment. Under this note, which is secured by such other property and equipment, we were required to make a monthly payment of approximately $52,000 and were to pay one lump-sum payment of $3.3 million at maturity in October 2017. This note carried an interest rate of 4.14% per annum.

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the promissory note were reinstated.

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 Prepetition Revolving Credit Facility. Derivative instruments premium financing was accounted for as debt and this indebtedness is pari passu with borrowings under the Prepetition 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 December 31, 2016, June 30, 2016 and 2015, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $0, $0 and $10.6 million, respectively.

Interest Expense

The filing of the Bankruptcy Petitions constituted an event of default with respect to the Predecessor’s existing debt obligations. Accordingly, the Predecessor’s pre-petition secured indebtedness under the Prepetition 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 were 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 Prepetition Revolving Credit Facility, the Predecessor accelerated the amortization of the remaining debt issuance costs related to its outstanding indebtedness, fully amortizing those costs as of March 31, 2016. The Predecessor continued to accrue interest on the Prepetition Revolving Credit Facility subsequent to the Petition Date until the Emergence Date. However, for all our other indebtedness, in accordance with accounting guidance in ASC 852, Reorganizations, the Predecessor accrued interest only up to the Petition Date. Contractual interest on

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Long-Term Debt  – (continued)

liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $176.5 million, representing interest expense from the Petition Date through Emergence Date, of which $123.7 pertained to the six month transition period ended December 31, 2016.

Interest expense consisted of the following (in thousands):

	Predecessor
	Six Months Ended December 31,		Year Ended June 30,
	2016		2016			2015			2014
Prepetition Revolving Credit Facility	$	11,670	$	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 – Prepetition Revolving Credit Facility		725		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		185		466			856			987
Bridge commitment fee		—		—			—			2,481
	$	12,580	$	405,658		$	323,308		$	162,728

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 — Asset Retirement Obligations

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

	Six Months Ended December 31, 2016			Year Ended June 30,
				2016			2015
Beginning of period total (Predecessor)	$	537,619		$	487,085		$	559,834
Liabilities acquired		—			66,700			—
Liabilities incurred and true-up to liabilities settled		13,880			34,167			40,820
Liabilities settled		(18,852	)		(78,273	)		(106,573	)
Liabilities sold		—			—			(65,752	)
Revisions*		(3,896	)		(36,750	)		8,675
Accretion expense		38,973			64,690			50,081
End of period total (Predecessor)		567,724			537,619			487,085
Less: End of period, current portion (Predecessor)					71,717			33,286
End of period, noncurrent portion (Predecessor)				$	465,902		$	453,799
Fair value fresh start adjustments		185,640
Less: End of period, current portion (Successor)		56,601
End of period, noncurrent portion (Successor)	$	696,763

* This downward revision for the year ended June 30, 2016 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.

See Note 4 — “Fresh Start Accounting” for the methodology and assumptions used in arriving at fair value fresh start adjustments on the Convenience Date.

Note 11 — 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 have historically entered into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We have used 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 ICE and/or Argus-LLS) plus the difference between the purchased put and the sold put strike price.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11 — Derivative Financial Instruments  – (continued)

Most of our crude oil production is Heavy Louisiana Sweet. We have historically included 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.

On March 14, 2016, the Fourteenth Amendment to the Prepetition Revolving Credit Facility 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 Prepetition Credit Agreement, and for such repayments to then result in an automatic and permanent reduction in EXXI Ltd’s borrowing base. Accordingly, on March 15, 2016, EXXI Ltd unwound and monetized all of its outstanding crude oil and natural gas contracts and $50.6 million was applied to reduce amounts outstanding under the Prepetition Revolving Credit Facility.

The Company did not enter into any derivative instruments during the six month transition period ended December 31, 2016, accordingly, there were no outstanding derivative contracts on December 31, 2016.

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

	Predecessor
	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).

	Predecessor
	Year Ended June 30,
Gain (loss) on derivative financial instruments	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

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11 — Derivative Financial Instruments  – (continued)

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 December 31, 2016, we had no outstanding derivative contracts and, accordingly, no deposits for collateral with our counterparties.

In February 2017, we entered into oil contracts (costless collars) benchmarked to Argus-LLS, to hedge 10,000 barrels per day of our production for the period from March 2017 to December 2017 with an average floor price of $52.30 and an average ceiling price of $57.43.

Note 12 — Stockholders’ Equity

Successor Common and Preferred Stock

Amendments to Articles of Incorporation or Bylaws

Pursuant to the Plan, on the Emergence Date, the Company’s certificate of incorporation and bylaws were amended and restated in their entirety. Each of the Company’s Certificate of Incorporation and second amended and restated bylaws became effective on the Emergence Date. Under our Certificate of Incorporation, the total number of all shares of capital stock that we are authorized to issue is 110 million shares, consisting of 100 million shares of the Company’s common stock, par value $0.01 per share, and 10 million shares of preferred stock, par value $0.01 per share.

In order to permit Mr. Reddin to be appointed CEO on an interim basis, the Board adopted the Third Amended and Restated Bylaws (the “Bylaws”) on February 2, 2017. Pursuant to the Bylaws, Section 4.1 was amended to provide that the positions of Chairman of the Board and Chief Executive Officer may be held by the same person only if (i) the two positions are held by the same person solely on an interim basis and (ii) the Board elects a Lead Independent Director for any period in which the two positions are held by the same person. Accordingly, the Bylaws added a new Section 3.8 to establish the position of Lead Independent Director and specified that position’s duties. The Bylaws provide that, during any period in which a Lead Independent Director is serving, the Lead Independent Director may, among other responsibilities, call and preside over all meetings of independent directors and, in the Chairman of the Board’s absence, preside over all meetings of the Company’s stockholders and of the Board.

After adopting the Bylaws, the Board appointed James “Jay” W. Swent III to serve as Lead Independent Director. Mr. Swent is an existing member of the Board, and will continue to serve as chairman of the Audit Committee of the Board.

Registration Rights Agreement

On the Emergence Date, the Company entered into a registration rights agreement with certain holders representing 10% or more of the Company’s common stock outstanding on that date or who acquire 10% or more of the Company’s common stock outstanding within six months of the Emergence Date (the “Holders”). The Registration Rights Agreement provides resale registration rights for the Holders’ Registerable Securities (as defined in the Registration Rights Agreement). On or before the date that is 60 days after the Emergence Date, the Company has agreed to file, and will thereafter use its commercially reasonable efforts to cause to be declared effective as promptly as practicable, a registration statement for the offer and resale of the Company’s common stock held by the Holders.

Pursuant to the Registration Rights Agreement, the Holders have customary demand, underwritten offering and piggyback registration rights, subject to the limitations set forth in the Registration Rights Agreement. Under their demand registration rights, holders may request Company to register all or a portion of their registerable securities, including on a delayed or continuous basis under Rule 415 of the Securities Act. Holders, as a group, are entitled to five demand registrations. Generally, the Company is required to provide notice of a demand request within ten days following the receipt of the demand notice to all

134

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Stockholders’ Equity  – (continued)

additional Holders, who may, in certain circumstances, participate in such demand registration. Under their underwritten offering registration rights, Holders also have the right to demand the Company to effectuate the distribution of any or all of such Holders’ Registerable Securities by means of an underwritten offering pursuant to an effective registration statement. Holders, as a group, are entitled to three underwritten offering requests in any twelve-month period. The Company is not obligated to effect a demand registration request or an underwritten demand registration request within 180 days of closing either a demand registration or an underwritten offering. The Company is required to use its reasonable best efforts to maintain the effectiveness of any such demand registration statement until the earlier of 270 days (or three years if a “shelf registration” is requested) after the Emergence Date and the consummation of the distribution by the participating Holders. Under their piggyback registration rights, if at any time the Company proposes to register an offering of its common stock for its own account, the Company must give at least ten business days’ notice to all Holders to allow them to include their shares in the registration statement, subject to certain limitations.

These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and the Company’s right to delay or withdraw a registration statement under certain circumstances. The Company will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective. The registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as blackout periods and, if an underwritten offering is contemplated, limitations on the number of shares to be included in the underwritten offering that may be imposed by the managing underwriter.

The obligations to register shares under the Registration Rights Agreement will terminate with respect to the Company and each Holder on the first date upon which such Holder no longer beneficially owns any Registerable Securities.

Warrant Agreement

On the Emergence Date, the Company issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims.

The warrants are exercisable from the date of the Warrant Agreement until the Expiration Date. The warrants are initially exercisable for one share of common stock per warrant at an initial exercise price of $43.66. The Warrant Exercise Shares and Exercise Price are subject to customary anti-dilution adjustments. No adjustments to the applicable Exercise Price or Warrant Exercise Shares are required unless the cumulative adjustments required would result in an increase or decrease of at least 1.0% in the applicable Exercise Price or the Warrant Exercise Shares. Additionally, if an adjustment in Exercise Price would reduce the Exercise Price to an amount below par value of the common stock, then such adjustment in Exercise Price will reduce the Exercise Price to the par value of the common stock.

Upon the occurrence of certain events prior to the Expiration Date constituting a recapitalization, reorganization, reclassification, consolidation, merger, sale of all or substantially all of the Company’s equity securities or assets or other transaction, in each case which is effected in such a way that the holders of common stock are entitled to receive (either directly or upon subsequent liquidation) cash, stock, securities or other assets or property with respect to or in exchange for common stock (any such event, “Organic Change”), each holder of warrants will be entitled to receive, upon exercise of a Warrant, such cash, stock, securities or other assets or property as would have been issued or payable in such Organic Change (as if the holder had exercised such Warrant immediately prior to such Organic Change) with respect to or in exchange, as applicable, for the number of Warrant Exercise Shares that would have been issued upon exercise of such warrants, if such warrants had been exercised immediately prior to the occurrence of such Organic Change.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Stockholders’ Equity  – (continued)

Holders of warrants are not entitled, by virtue of holding warrants, to vote, to consent, to receive dividends, to consent or to receive notice as stockholders with respect to any meeting of stockholders for the election of the Company’s directors or any other matter, or to exercise any rights whatsoever as the Company’s stockholders unless, until and only to the extent such holders become holders of record of shares of common stock issuable upon exercise of the warrants.

The warrants permit a holder of warrants to exercise the warrants for net share or “cashless” settlement in lieu of paying the Exercise Price by authorizing the Company to withhold and not issue to such holder, in payment of the Exercise Price, a number of such Warrant Exercise Shares equal to (i) the number of Warrants Exercise Shares for which the warrants are being exercised, multiplied by (ii) the Exercise Price, and divided by (iii) the Current Sale Price (as defined in the Warrant Agreement) on the Exercise Date.

Shares of common stock and warrants issued and outstanding

On the Emergence Date, the Company issued (i) 27,897,739 shares of common stock, pro rata, to holders of the claims arising from the Second Lien Notes, (ii) 3,985,391 shares of common stock, pro rata, to holders of the claims arising from the EGC Unsecured Notes Claims, (iii) 1,328,464 shares of common stock, pro rata, to holders of the claims arising from the EPL Unsecured Notes Claims, (iv) 1,271,933 warrants, pro rata, to holders of the EGC Unsecured Notes Claims; and (v) 847,956 warrants, pro rata, to holders of the EPL Unsecured Notes Claims. The Confirmation Order and Plan provide for the exemption of the offer and sale of the shares of common stock and the warrants (including shares of Common Stock issuable upon the exercise thereof) from the registration requirements of the Securities Act pursuant to Section 1145(a)(1) of the Bankruptcy Code. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied.

As of December 31, 2016, 33,211,594 shares of common stock and 2,119,889 warrants were outstanding.

Predecessor Common Stock

EXXI Ltd’s common stock was traded on the NASDAQ under the symbol “EXXI” prior to its delisting in connection with the commencement of the Chapter 11 proceedings. EXXI Ltd’s common stock resumed trading on the OTC Pink under the symbol “EXXIQ” on April 25, 2016. As a result of filing of the Bankruptcy Petitions, EXXI Ltd’s common stock was suspended from trading on the NASDAQ on April 25, 2016. A Form 25-NSE was filed with the SEC on May 19, 2016, which removed EXXI Ltd’s securities from listing and registration on NASDAQ. EXXI Ltd’s shareholders were entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. EXXI Ltd had 200,000,000 authorized common shares, par value of $0.005 per share.

Late in fiscal year 2015, the Board of Directors of EXXI Ltd (the “Predecessor Board”) decided to suspend the declaration of quarterly dividends on our common stock. During fiscal year 2015, EXXI Ltd paid to holders of its 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, EXXI Ltd paid to holders of its 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 EXXI Ltd’s securities would 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 filing the Bankruptcy Petitions, the associated public interest concerns raised by the Bankruptcy Petitions, concerns regarding the residual equity interest of EXXI Ltd’s listed securities holders and concerns about EXXI Ltd’s ability to sustain compliance with all requirements for continued listing on NASDAQ. On February 24, 2016, EXXI Ltd received a deficiency notice from NASDAQ stating that, based on the closing bid price of its common stock for the prior 30 consecutive business days, EXXI Ltd 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

136

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Stockholders’ Equity  – (continued)

EXXI Ltd’s 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 EXXI Ltd’s securities from listing and registration on NASDAQ.

EXXI Ltd’s securities resumed trading on the OTC Markets Group Inc.’s OTC Pink under the symbol “EXXIQ” on April 25, 2016. On December 30, 2016, upon emergence from the Chapter 11 Cases, EXXI Ltd’s common shares were removed from the OTC Market.

The Predecessor’s 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 Predecessor 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 reduced the likelihood that changes in EXXI Ltd’s investor base would limit its future use of its tax benefits, which would significantly impair the value of the benefits to all shareholders. To implement the Rights Plan, the Predecessor Board declared a non-taxable dividend of one preferred share purchase right (“Rights”) for each outstanding share of common stock of EXXI Ltd. The rights were exercisable if a person or group acquired 4.9% or more of EXXI Ltd’s common stock. The rights were also exercisable if a person or group that already owned 4.9% or more of EXXI Ltd’s common stock acquired additional shares (other than as a result of a dividend or a stock split). EXXI Ltd’s existing shareholders that beneficially owned in excess of 4.9% of the common stock were “grandfathered in” at their then ownership level. If the rights were to have become exercisable, all holders of rights, other than the person or group triggering the rights, would have been entitled to purchase EXXI Ltd’s common stock at a 50% discount. Rights held by the person or group triggering the rights will became void and will not be exercisable.

The Rights traded with shares of EXXI Ltd’s common stock and expired on February 15, 2017. As of December 30, 2016, 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 EXXI Ltd’s 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 EXXI Ltd’s common stock. Upon conversion, EXXI Ltd elected to issue shares of its common stock and delivered 915,385 shares of its common stock with fractional shares settled in cash. For more information see Note 9 — “Long-Term Debt,” under the caption 3.0% Senior Convertible Notes Due 2018.

In May 2013, the Predecessor Board approved a stock repurchase program authorizing it to repurchase up to $250 million in value of its common stock for an extended period of time, in one or more open market transactions. The repurchase program authorized EXXI Ltd 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 did not obligate EXXI Ltd to acquire any particular amount of common stock and could have been modified or suspended at any time and could have been terminated prior to completion. EXXI Ltd suspended the repurchase program indefinitely to reduce our capital needs. EXXI Ltd did not make any repurchases under its repurchase program during the fiscal years ended June 30, 2016 and 2015. During the year ended June 30, 2014, EXXI Ltd incurred $94.2 million to

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Stockholders’ Equity  – (continued)

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 remained available for repurchases under the share repurchase program.

In February 2014, EXXI Ltd retired 2,087,126 shares of its common stock, resulting in 7,329,100 shares of its common stock being held in treasury. On June 3, 2014, EXXI Ltd reissued the entire 7,329,100 shares of its common stock in treasury as part of our common stock issued to EPL stockholders in connection with EPL Acquisition.

As discussed in Note 5 — “Acquisitions and Dispositions,” upon closing of the EPL Acquisition, EXXI Ltd issued 23,320,955 shares of our common stock, including the treasury shares, as noted above, as part of the Merger Consideration.

As discussed in Note 9 — “Long-Term Debt,” in November 2013 EXXI Ltd 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 the 3.0% Senior Convertible Notes in November 2013, EXXI Ltd repurchased 2,776,200 shares of its common stock for approximately $76 million, at a weighted average price per share, excluding fees of $27.39.

Predecessor Preferred Stock

EXXI Ltd’s bye-laws authorized the issuance of 7,500,000 shares of preferred stock. The Predecessor Board was 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.

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”) were 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 were to be paid in cash, shares of EXXI Ltd’s common stock, or a combination thereof.

As a result of filing the Bankruptcy Petitions, EXXI Ltd no longer accrued dividends on preferred stock, accordingly, EXXI Ltd suspended the quarterly dividends on the 5.625% Preferred Stock and the 7.25% Preferred Stock effective January 1, 2016. Preferred stock dividends that would have accrued from the Petition Date through December 31, 2016 totaled approximately $5.7 million.

The 5.625% Preferred Stock was convertible into 9.8353 shares of EXXI Ltd’s common stock at the conversion rate and price in effect on the conversion date. At June 30, 2015, the conversion rate was 10.4765 common shares per preferred share. On or after December 15, 2013, EXXI Ltd was permitted to 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 EXXI Ltd’s common stock equals or exceeds 130% of the then-prevailing conversion price. The 5.625% Preferred Stock became callable beginning December 15, 2013 if EXXI Ltd’s common stock trading price exceeded $32.45 per share for 20 of 30 consecutive trading days.

The 7.25% Preferred Stock was convertible into 8.77192 shares of EXXI Ltd’s common stock at the conversion rate and price in effect on the conversion date. At June 30, 2015, the conversion rate was 9.3439 common shares per preferred share. On or after December 15, 2014, EXXI Ltd was permitted to 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 EXXI Ltd’s common stock equals or exceeds 150% of the then-prevailing conversion price.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Stockholders’ Equity  – (continued)

Conversion of Preferred Stock

During the six months ended December 31, 2016, we cancelled and converted 300,248 shares of our 5.625% Preferred Stock into a total of 3,145,549 shares of common stock using a conversion rate of 10.4765 common shares per preferred share.

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 EXXI Ltd’s equity securities, including its 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 EXXI Ltd’s outstanding Stock, as determined in accordance with applicable rules under Section 382 of the IRC (“Tax Ownership”).

As a result of the Plan, there are no assets remaining in EXXI Ltd, and under Bermuda law, preferred stockholders of EXXI Ltd will receive no payments. EXXI Ltd will be dissolved at the conclusion of the Bermuda Proceeding, and as such, the preferred stockholders will no longer have any interest in EXXI Ltd as a matter of Bermuda law.

Note 13 — Supplemental Cash Flow Information

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

	Predecessor
	Six Months Ended December 31,		Year Ended June 30,
	2016		2016		2015		2014
Cash paid for interest	$	7,493	$	229,569	$	243,238	$	139,575
Cash paid for income taxes		—		150		933		3,641

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13 — Supplemental Cash Flow Information  – (continued)

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

	Predecessor
	Six Months Ended December 31,			Year Ended June 30,
	2016			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		10,242			(37,151	)		(168,569	)		115,696
Acquisition of property against joint interest billings receivable		(1,500	)		—			—			—
Inventory transferred to oil and natural gas properties		—			7,081			—			—
Changes in asset retirement obligations		9,984			(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 14 — Employee Benefit Plans

Successor Long Term Incentive Plan

2016 Long Term Incentive Plan

As of the Emergence Date, the Company entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the go-forward compensation for our officers, directors, employees and consultants (“Service Providers”). The total number of shares of our common stock reserved and available for delivery with respect to awards under the 2016 LTIP is 1,859,552 shares (or 5% of the total new equity). Our Board will determine the types of equity based awards (which may include stock option, stock appreciation rights, restricted stock, restricted stock units, bonus stock awards, performance awards, other stock based awards or cash awards) and the terms and conditions (including vesting and forfeiture restrictions) of such awards. Awards under the 2016 LTIP will be awarded to the Service Providers selected in the discretion of our Board; provided, however, that 3% of the 5% total new equity on a fully diluted basis reserved under the 2016 LTIP must be allocated by our Board no later than 120 days after the Emergence Date.

Subsequent to December 31, 2016, 106,250 restricted shares were issued to members of the Board pursuant to the terms of the 2016 LTIP and the Non-Employee Director Compensation Policy (the “Director Compensation Policy”) discussed below.

Non-Employee Director Compensation

On January 6, 2017, the Board adopted the Non-Employee Director Compensation Policy (the “Director Compensation Policy”), pursuant to which each non-employee director is entitled to receive, or has received, the compensation as set forth in the Director Compensation Policy. The Director Compensation Policy provides for annual cash retainers of (i) $75,000 for serving on the Board or $125,000 for serving as the Non-Executive Chairman of the Board; (ii) $25,000 for serving as the Chairman of the Audit Committee and $12,500 for serving as a member of the Audit Committee; (iii) $25,000 for serving as the Chairman of the Compensation Committee and $12,500 for serving as a member of the Compensation Committee; and (iv) $10,000 for serving as the Chairman of the Nomination and Governance Committee and $5,000 for

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Note 14 — Employee Benefit Plans  – (continued)

serving as a member of the Nomination and Governance Committee. As set forth in the Director Compensation Policy, each non-employee director is also eligible to receive (a) an initial restricted stock unit award of $200,000 or $300,000 for the Non-Executive Chairman of the Board and (b) $130,000 of annual restricted stock units or $175,000 for the Non-Executive Chairman of the Board. The deemed value utilized by the Board for purposes of the equity awards to be granted in January 2017 pursuant to the Director Compensation Policy is $20 per share. All equity awards granted pursuant to the Director Compensation Policy are subject to the terms and conditions of the 2016 LTIP, to such director’s continued service on the Board, and to acceleration upon the occurrence of specified events.

On February 2, 2017, the Board added the position of Lead Independent Director with a cash retainer of $50,000 for each year or partial year of service.

Predecessor Long Term Incentive Plan

Prior to the Emergence Date, the Predecessor Company maintained the Energy XXI Services, LLC 2006 Long-Term Incentive Plan (the “2006 Incentive Plan”) an incentive and retention program for its employees. Participation shares (or “Restricted Stock Units”) were issued from time to time at a value equal to its common share price at the time of issue. The Restricted Stock Units generally vested equally over a three-year period. When vesting occurred, the Predecessor Company paid the employee an amount equal to the Predecessor Company’s then current common share price times the number of Restricted Stock Units. The Predecessor Company 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 vested equally over a three-year period. In addition, prior to the Emergence Date, the Predecessor Company maintained the director compensation program which provided for an annual stock award in lieu of cash payment, employee stock purchase plan which allowed employees to purchase its 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 and had granted stock options to its certain officers.

As a result of the Plan, there are no assets remaining in the Predecessor Company, all common shares of the Predecessor Company will be cancelled and its shareholders will receive no payments with respect to the common shares, and the Predecessor Company will be dissolved pursuant to Bermuda law at the conclusion of the Bermuda Proceeding. As a result, all awards under the 2006 Incentive Plan that remained unvested, including performance-based awards and all of share-based compensation plans at the Emergence Date were cancelled.

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Note 14 — Employee Benefit Plans  – (continued)

Defined Contribution Plans

Prior to the Emergence Date, the Predecessor Company’s employees were covered by a discretionary noncontributory profit sharing plan. The plan provided for annual discretionary employer contributions that could vary from year to year. The Predecessor Company also sponsored a qualified 401(k) Plan that provided for matching. Pursuant to the terms of the Plan, on the Emergence Date we assumed the Predecessor Company’s defined contribution plans. The contributions under these plans were as follows (in thousands):

	Predecessor
	Six Months Ended December 31,		Year Ended June 30,
	2016		2016		2015			2014
Profit Sharing Plan	$	—	$	—	$	(768	)	$	4,833
401(k) Plan		638		2,852		3,192			3,395
Total contributions	$	638	$	2,852	$	2,424		$	8,228

Note 15 — Related Party Transactions

Successor Related Party Transactions

On the Emergence Date, the Company entered into a Registration Rights Agreement with the Holders representing 10% or more of the Common Stock outstanding on that date or who acquire 10% or more of the Common Stock outstanding within six months of the Emergence Date. On the Emergence Date, the Company also entered into the Warrant Agreement with Continental Stock Transfer & Trust Company, as Warrant Agent and issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims. For more information see Note 12 — “Stockholders’ Equity.”

Predecessor 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, the Predecessor Board appointed one of its members, James LaChance, to serve as interim Chief Strategic Officer. In that position, Mr. LaChance pursued discussions with 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 Predecessor 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, EXXI Ltd 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

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 — Related Party Transactions  – (continued)

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 Predecessor Board’s 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 EXXI Ltd’s 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 Predecessor Board 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 EXXI Ltd’s 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 Predecessor 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 Predecessor 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 did not receive any compensation for serving as Chairman of the Board, other than pursuant to director compensation programs that were applicable to other non-employee directors.

During the years ended June 30, 2015 and 2014, the Company’s former Chief Executive Officer and President John D. Schiller, Jr. borrowed funds from personal acquaintances or their affiliates, certain of whom provide services to us (“Vendor Loans”). During the six months ended December 31, 2016 certain of those lenders provided services to the Company totaling $3.3 million. During the years ended June 30, 2016, 2015 and 2014, certain of those lenders provided services to the Predecessor Company totaling $35.9 million, $34.7 million and $38.7 million, respectively. During 2014, one of the directors on the Predecessor Board made a personal loan to Mr. Schiller at a time prior to becoming a member of the Predecessor Board 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 EXXI Ltd’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 the Predecessor Board in October 2010, had an ownership interest. These entities provide us with oil field services. During the six month transition period ended December 31, 2016 no payments were made and during fiscal year ended June 30, 2016, 2015 and 2014 EXXI Ltd made aggregate payments of approximately $5.6 million, $2.0 million and $0.6 million, respectively to these entities for those services.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — 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):

	Successor			Predecessor
	On December 31,			Six Months Ended December 31,		Year Ended June 30,
	2016			2016		2016			2015			2014
Net income (loss)	$	(406,275	)	$	2,653,903	$	(1,918,751	)	$	(2,433,838	)	$	18,125
Preferred stock dividends		—			—		8,394			11,468			11,489
Net income (loss) attributable to common stockholders	$	(406,275	)	$	2,653,903	$	(1,927,145	)	$	(2,445,306	)	$	6,636
Weighted average shares outstanding for basic EPS		33,212			98,337		95,822			94,167			74,375
Add dilutive securities		—			6,450		—			—			70
Weighted average shares outstanding for diluted EPS		33,212			104,787		95,822			94,167			74,445
Earnings (loss) per share
Basic	$	(12.23	)	$	26.99	$	(20.11	)	$	(25.97	)	$	0.09
Diluted	$	(12.23	)	$	25.33	$	(20.11	)	$	(25.97	)	$	0.09

On December 31, 2016, 2,119,889 shares of potential Successor common stock were excluded from the diluted average shares due to an anti-dilutive effect. 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 17 — 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.

On June 17, 2016, the SEC filed a proof of claim against EXXI Ltd asserting a general unsecured claim in the amount of $3.9 million based on alleged violations of the federal securities laws by EXXI Ltd pertaining to the failure to disclose certain funds borrowed by our former President and CEO John D. Schiller, Jr. from personal acquaintances or their affiliates, certain of whom provided EXXI Ltd and certain of its subsidiaries with services and Mr. Schiller’s pledge of EXXI Ltd stock to a certain financial institution in the second half of 2014. The claim against EXXI Ltd has been classified as a general unsecured claim subject to a cap of approximately $1.4 million, which will be paid by EGC, under the Plan and will be subject to discharge, settlement and release in connection with the Chapter 11 Cases, and will receive the treatment provided to holders of general unsecured claims. The Debtors anticipate that they will object to the SEC’s claim.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Commitments and Contingencies  – (continued)

Lease Commitments.  We have non-cancelable operating leases for office space and other assets that expire through December 31, 2018. In addition, on June 30, 2015, we entered into an agreement to assume the operating lease agreement for the Grand Isle Gathering System from our Predecessor as further described below. As of December 31, 2016, future minimum lease commitments under our operating leases are as follows (in thousands):

Year Ending December 31,	Successor
2017	$	35,956
2018		36,017
2019		36,509
2020		43,545
2021		49,598
Thereafter		200,751
Total	$	402,376

For the six month transition period ended December 31, 2016, rent expense, including rent incurred on short-term leases but excluding the GIGS Lease, (defined below), was approximately $11.9 million. For the years ended June 30, 2016, 2015 and 2014, rent expense, including rent incurred on short-term leases but excluding the GIGS Lease, 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 Predecessor 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 six month transition period ended December 31, 2016 was approximately $17 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. On December 30, 2016, the Tenant, the Company and Grand Isle Corridor entered into an Assignment and Assumption Agreement pursuant to which the Tenant assigned to the Company its right, title, interest, and obligations in and to the purchase and sale agreement relating to the GIGS. Additionally, Reorganized EGC assumed the obligations of EXXI Ltd as guarantor of Tenant’s obligations under the GIGS Lease pursuant to the Assignment and Assumption of Guaranty and Release Agreement, dated December 30, 2016.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Commitments and Contingencies  – (continued)

Under the GIGS Lease, an event of default would have been triggered by the Tenant upon (i) the filing by either the Tenant or EXXI Ltd of a Bankruptcy Petition or (ii) the failure of either the Tenant, EXXI Ltd or now EGC to make any payment of principal or interest with respect to certain material debt of the Tenant, EXXI Ltd, as the former guarantor, or EGC 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, the Debtors’ filing of the Bankruptcy Petitions and failure to comply with our material debt instruments, would, among other things, have allowed Grand Isle Corridor to terminate the Lease.

As a result, the Tenant and Grand Isle Corridor entered into a waiver to the GIGS Lease, dated as of April 13, 2016, 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.

Letters of Credit and Performance Bonds.  As of December 31, 2016, we had $388.2 million of performance bonds outstanding and $225 million in letters of credit issued to ExxonMobil relating to assets in the Gulf of Mexico. We are a lessee and operator of oil and natural gas leases on the 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. In particular, compliance with lease requirements includes responsibility for decommissioning obligations 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, and the BOEM generally requires that lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. In July 2016, the BOEM issued a new NTL that provided more stringent requirements for additional security to satisfy decommissioning obligations and eliminating previous exemptions from the posting of financial assurances. Consequently, as of December 31, 2016, we have submitted approximately $226.7 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 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 conditions of

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Commitments and Contingencies  – (continued)

the Long-Term Plan, we have submitted supplemental bonds to the BOEM for our sole liability properties addressed under the Long-Term Plan; however, the BOEM increased the financial assurance amount for one of those sole liability properties subsequent to execution of the Long Term Plan and, thus, on June 28, 2016, we submitted the Proposed Plan Amendment that would revised the Long-Term Plan and reflect such increase, and we are awaiting the BOEM’s further response on the Proposed Plan Amendment.

We submitted a Proposed Plan Amendment on June 28, 2016 that would revised the executed Long-Term Plan. We are currently awaiting the BOEM’s further response on the Proposed Plan Amendment. Consistent with the BOEM’s issuance of the new NTL in July 2016 relating to the need for additional security to satisfy decommissioning obligations and its subsequent issuance of the January 2017 Extension, however, the BOEM’s current focus is on sole liability properties. Consequently, the BOEM issued us the January 5, 2017 Ordering Letter, directing us to provide BOEM with additional security for certain sole liability properties in the OCS that are held or operated by us in the OCS and specified in the letter within 60 calendar days of receipt of the letter. The amount of additional security required of us under the January 5, 2017 Ordering Letter is approximately $5.1 million. On January 26, 2017, the Company submitted to the BOEM its January 2017 Proposed Plan Amendment that would satisfy the January 5, 2017 Ordering Letter for approximately $5.1 million in additional sole liability property coverage while reserving the Company’s right to dispute the decommissioning liability amount calculated by the BSEE. Consequently, while we have submitted or plan to submit additional supplemental bonds to the BOEM for our sole liability properties addressed under the Long-Term Plan, and are awaiting the BOEM’s response on the Proposed Plan Amendment and the January 2017 Proposed Plan Amendment, we have not yet been directed by the BOEM to submit financial assurance for our sole and non-sole liability properties (that is, our offshore OCS properties that are not sole liability properties) addressed under the Long-Term Plan.

In a recent development, however, the BOEM publicly announced on February 17, 2017 that it will withdraw sole liability orders previously issued to OCS lease and grant holders in December 2016 and January 2017 to allow time for the new Presidential Administration to review the BOEM’s current financial assurance program, as modified in 2016 by NTL 2016-N01. Whether, and to what extent, orders for non-sole liability properties will be re-issued by the BOEM will be re-evaluated in conjunction with the evaluation currently underway for OCS non-sole liability properties ordered by the BOEM as part of the six-month extension granted by the BOEM in January 2017. The BOEM may elect to re-issue its sole liability orders before the end of the six-month extended period established for the non-sole liability properties if the agency determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

Due to the BOEM’s recent retractions in the first two months of 2017 relating to the provision of financial assurance for OCS decommissioning obligations, we are currently uncertain as to the timing and amount of coverage that will be required by the BOEM pursuant to its OCS financial assurance program. However, based on currently understood parameters as reflected in the Long-Term Plan and the Proposed Plan Amendment, we currently expect to ultimately address the financial coverage of our sole liability and non-sole liability properties in accordance with the Long-Term Plan and consistent with evolving guidelines under the September 2016 NTL, but we cannot provide any assurance at this time on when such financial coverage for our non-sole liability properties will be directed to be submitted by the BOEM or on how we plan to structure and fund such coverages.

On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with ExxonMobil, it was agreed that subsequent to the Predecessor Company’s emergence from the Chapter 11 proceedings, the letters of credit issued in favor ExxonMobil would be reduced to $200 million from the existing amount of $225 million and currently documents are being formalized to effect such reduction.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Commitments and Contingencies  – (continued)

Notwithstanding the BOEM’s July 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, as it may be revised by the Proposed Plan Amendment, the July 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 have $49.6 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors as of December 31, 2016, we may be required to provide additional cash collateral in the future-to support the issuance of such bonds or other financial security. 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 December 31, 2016, our restricted cash included $25.6 million in cash collateral associated with our bonding requirements, approximately $26.0 million in a financial institution to be used for paying restructuring expenses in accordance with the Plan 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 interest 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.

Note 18 — Income Taxes

Successor Income Taxes

On the Emergence Date, as described in Note 3 — Chapter 11 Proceedings, the Company and the Predecessor engaged in several internal restructuring transactions that: (i) assigned all of Predecessor’s assets (directly or indirectly) to EGC, and (ii) separated EXXI Ltd, Energy XXI (US Holdings) Limited (Bermuda), Energy XXI, Inc., and Energy XXI USA from EGC. This had the effect, among other things, of isolating the original parent-level equity ownership and certain intercompany loans (the “Intercompany Loans”) from EGC. Then, pursuant to the Plan, the EGC Unsecured Notes, EPL 8.25% Senior Notes, Prepetition Revolving Credit Facility and other obligations were extinguished. Absent an exception, a debtor recognizes CODI upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Tax Code provides that a debtor in a bankruptcy case (such as the Chapter 11 Cases) may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the Plan. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from the Chapter 11 Cases, the amount of CODI realized was approximately $2,600 million, which reduced the Company’s U.S. NOL carryovers of $486 million to zero, and further reduced the Company’s tax basis in producing properties (subject to future recovery through tax DD&A deductions) and its investment in the stock of EPL by $2,137 million. This reduction in tax

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 18 — Income Taxes  – (continued)

attributes occurred on the first day of the Company’s first tax year subsequent to the Emergence Date, as one effect of the Plan was to terminate the Predecessor’s fiscal income tax reporting period on the Emergence Date.

Tax Code Sections 382 and 383 provide an annual limitation with respect to the ability of a corporation to utilize its tax attributes, including as the tax basis in certain assets (net unrealized built-in-losses, or “NUBILs”), against future U.S. taxable income in the event of a change in ownership. The Company’s emergence from the Chapter 11 Cases was considered a change in ownership for purposes of Tax Code Section 382. The limitation under the Tax Code is based on the value of the loss corporation as of the Emergence Date. However, this and prior ownership changes and resulting annual limitation will have limited, if any, effect on the Company’s NOLs since all of the NOLs were extinguished by the Tax Attribute Reduction Rules. There is the possibility of deferral of recognition of certain portions of tax DD&A by the Tax Attribute Reduction Rules that would affect the timing of offsetting future taxable income, but would not affect income tax expense. The remaining tax bases of our oil and natural gas properties are less than their respective book carrying values as determined in fresh-start accounting such that we have recorded a deferred tax liability for those properties. We have recorded a deferred tax asset for the asset retirement obligation (which has no tax basis and will be tax deductible or result in additional tax basis in assets when settled) and other items that exceed the deferred tax liability for oil and natural gas properties. As such, we have recorded a valuation allowance of $174.5 million at December 31, 2016, which results in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of Predecessor losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets were unrecoverable.

As a result of the fresh start accounting, virtually all historic deferred tax assets and liabilities were eliminated, including the accrued outbound 30% withholding tax on the intercompany loans from the Predecessor’s Bermuda parent, as these obligations were extinguished in the Plan are not obligations of the Successor entities. With the NOL carryover being reduced by the Tax Attribute Reduction Rules, the principal deferred tax assets and liabilities of the Successor after fresh-start accounting relate to our oil and gas properties.

Additionally, the Successor Company is changing its U.S. federal and state tax years to December 31, consistent with its financial reporting year end, with calendar 2017 being its first tax year post-discharge.

Predecessor Income Taxes

The Predecessor Company was a Bermuda company and was generally not subject to income tax in Bermuda. It historically operated through its various subsidiaries in the United States, and, accordingly, U.S. income taxes were provided based upon those U.S. operations and U.S. withholding tax on interest owed to its Bermuda parent on intercompany indebtedness. Pursuant to the Restructuring Support Agreement discussed in Note 3 — “Chapter 11 Proceedings, Liquidity and Capital Resources,” the Predecessor 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 Predecessor’s income tax year or income tax reporting requirements.

The Predecessor’s Bermuda companies recorded 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 through the Petition Date. During the year ended June 30, 2016, and for the six-month period ended December 30, 2016, no cash withholding tax payments were made on interest expense or management fees accrued to the Bermuda entities. The Predecessor recorded 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 the Bermuda parent was not a current liability due nor was listed as a pre-petition tax liability

149

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 18 — Income Taxes  – (continued)

in the bankruptcy petition filed on the Petition Date. During the year ended June 30, 2015, $0.9 million cash was paid in U.S. withholding taxes as a result of payments of interest on indebtedness and management fees to the 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.

The Predecessor 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 the NOL carryforwards. Section 61(a)(12) of the Tax Code generally provides, in pertinent part, CODI is treated as ordinary income subject to current taxation. The Predecessor completed several purchases of indebtedness during the year ended June 30, 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%. Tax Code 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 Predecessor would have been subject to a current cash AMT payment due to the 90% limitation in NOL usage against this tax. Management believes, more likely than not, that prior to the bankruptcy filing, the Predecessor was, for income tax purposes, insolvent as defined in Tax Code section 108(a)(1)(B) at the times of significant indebtedness repurchases and thus the exclusion applies to significant indebtedness repurchases that constitute CODI. As such, no cash AMT payments were made during the year ended June 30, 2016, or the six-month period ended December 31, 2016.

In accordance with Tax Code Section 382, certain transfers of Predecessor equity, or issuances of equity in connection with the restructuring, could have impaired the ability to utilize NOL carryforwards and the tax basis of property 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. There was 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. However, in light of the reduction of NOL carryforwards as a result of the Tax Attribute Reduction Rules, no Tax Code section 382 ownership change resulted in a limitation or loss of NOLs of the Predecessor.

Under Louisiana law, companies are required to file tax returns on a separate company basis; as such, EPL and EGC did not file a combined nor consolidated Louisiana income tax return. The valuation allowance of $23.8 million at June 30, 2014 related to EXXI Ltd’s separate company Louisiana NOL carryforwards that management 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 expectations regarding future taxable income, consistent with net losses recorded during the current fiscal year (that are heavily influenced by oil and gas property impairments), caused management to record a net increase in the valuation allowance of $356.8 million resulting in a balance of $379.3 million at June 30, 2015. Due to continuing losses, management recorded an additional valuation allowance of $650 million resulting in a balance of $1,029.3 at June 30, 2016. This increase to the valuation allowance against net deferred tax assets due to management’s judgment that the existing U.S. federal and State of Louisiana NOL carryforwards are not, on a more-likely-than-not basis, likely recoverable in

150

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 18 — Income Taxes  – (continued)

future years. Management evaluated the need for the valuation allowance based on current and expected earnings and other factors, and adjusted it accordingly. No additional Louisiana tax attributes were recorded and no adjustment to the Louisiana valuation allowance was made in the six months ended December 31, 2016.

Our income (loss) before income taxes attributable to U.S. and non-U.S. operations are as follows (in thousands):

	Successor			Predecessor
	On December 31,			Six Months Ended December 31,			Year Ended June 30,
	2016			2016			2016			2015			2014
U.S. income (loss)	$	(406,275	)	$	2,656,509		$	(1,913,718	)	$	(3,050,659	)	$	43,915
Non-U.S. income (loss)		—			(2,606	)		(5,120	)		3,471			9,230
Income (loss) before income taxes	$	(406,275	)	$	2,653,903		$	(1,918,838	)	$	(3,047,188	)	$	53,145

The components of our income tax expense (benefit) are as follows (in thousands):

	Successor		Predecessor
	On December 31,		Six Months Ended December 31,		Year Ended June 30,
	2016		2016		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

151

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 18 — Income Taxes  – (continued)

The following is a reconciliation of statutory income tax expense to our income tax provision (benefit) (in thousands):

	Successor			Predecessor
	On December 31,			Six Months Ended December 31,			Year Ended June 30,
	2016			2016			2016			2015			2014
Income (loss) before income taxes	$	(406,275	)	$	2,653,903		$	(1,918,838	)	$	(3,047,188	)	$	53,145
Statutory rate		35	%		35	%		35	%		35	%		35	%
Income tax expense (benefit) computed at statutory rate		(142,196	)		928,866			(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		142,196			(1,029,335	)		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 and restructuring costs		—			31,699			—			440			1,853
Fresh start adjustments to deferred tax balances:
Asset retirement obligation		—			190,923			—			—			—
Net operating loss		—			163,027			—			—			—
Accrued interest expense		—			115,560			—			—			—
Oil and natural gas properties and other property and equipment		—			615,146			—			—			—
Deferred state income taxes		—			54,793			—			—			—
Withholding taxes		—			(81,635	)		—			—			—
Cancellation of stockholders deficit		—			(290,665	)		—			—			—
Cancellation of indebtedness income		—			(702,972	)		—			—			—
Other fresh start deferred income taxes					3,788
Goodwill impairment		—			—			—			115,253			—
Other – Net		—			805			5,097			2,567			3,631
Income tax expense (benefit)	$	—		$	—		$	(87	)	$	(613,350	)	$	35,020

For the six-month period ended December 31, 2016, we recorded no income tax expense or benefit. We incurred an additional net operating loss during this period that was reduced by non-deductible restructuring costs, consistent with prior periods. We additionally recognized significant CODI however; this CODI was excluded from taxation since it was incurred pursuant to the Chapter 11 Cases. We could not record an additional deferred tax asset for this net operating loss carryforward because it was completely eliminated by

152

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 18 — Income Taxes  – (continued)

the Tax Attribute Reduction Rules. The most significant difference in the effective tax rate for the Predecessor’s year ended June 30, 2016 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. In fresh start accounting, but prior to recording the property impairment, a net deferred tax asset was recorded by the company of $32.2 million. This amount was increased by $142.2 million to reflect the additional deferred tax asset created by the property impairment for which the company recorded an additional valuation allowance of an equal amount. The components of deferred taxes are detailed in the table below (in thousands):

	Successor			Predecessor
	On December 31,			June 30,
	2016			2016			2015
Deferred tax assets – non current
Oil, natural gas properties and other property and equipment	$	—		$	646,294		$	—
Asset retirement obligation		263,677			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		11,830			23,056			14,851
Total deferred tax assets – non current		275,507			1,130,238			809,752
Deferred tax liabilities
Oil, natural gas properties and other property and equipment		(101,045	)		—			(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		(101,045	)		(100,903	)		(430,460	)
Valuation allowance		(174,462	)		(1,029,335	)		(379,292	)
Net deferred tax asset (liability)	$	—		$	—		$	—

At June 30, 2016, the Predecessor had a U.S. federal NOL carryforward of approximately $285 million, and a state NOL carryforward of approximately $800 million, including amounts carried into the Predecessor’s U.S. group from the EPL acquisition. At December 30, 2016, immediately prior to the Emergence Date, the Predecessor had US federal NOL carryforwards of $586 million. The regular U.S. federal income tax NOL’s would have expired in various amounts beginning in 2026 and ending in 2035. The reason for the decrease in the NOL carryforward at December 31, 2016 and June 30, 2016 is due to the required reduction in the tax attribute from excluding CODI from debt repurchases while insolvent and Bankruptcy Court cancellation of indebtedness pursuant to the Plan. No CODI was recognized in the six-month period prior to the Emergence Date until the effective time of the Plan; as such, there was no adjustment to the NOL carryover or other tax attribute from CODI exclusion during this period.

153

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 18 — Income Taxes  – (continued)

The Predecessor did not record any reserves for uncertain tax positions. At June 30, 2016, the Predecessor had a gross unrecorded noncurrent deferred tax asset of $13.2 million representing a percentage depletion carryover resulting from the EPL acquisition, which was unchanged at December 30, 2016, prior to the effective time of the Plan.

The Predecessor filed 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 management that they had completed their examination of the 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.

Note 19 — 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”), Chevron USA (“Chevron”) and Shell Trading Company (“Shell”) accounted for approximately 27%, 26%, and 26%, respectively, of our total oil and natural gas revenues during the six months ended December 31, 2016. Trafigura accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2016. Chevron accounted for approximately 22% and 24% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015, respectively. 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 December 31, 2016 and 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.

154

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 20 — Fair Value

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 (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 prior to their cancellation, the fair value was estimated based on quoted prices in a market that was not an active market, which are Level 2 inputs within the fair value hierarchy. The carrying value of the Exit 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.

Upon adoption of fresh start accounting, the non-recurring fair value adjustment related to our property and equipment, asset retirement obligation and common stock warrants was $1,007.4 million, $185.6 million and $8.1 million, respectively using Level 3 inputs within the fair value hierarchy. See Note 4 — “Fresh Start Accounting.”

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 11 — “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.

155

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 20 — Fair Value  – (continued)

During the six months ended December 31, 2016 and 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):

	Predecessor
	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):

	Successor				Predecessor
	December 31, 2016				June 30, 2016				June 30, 2015
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Prepetition Revolving Credit Facility(1)	$	—	$	—	$	99,836	$	99,836	$	150,000	$	150,000
Exit Facility		73,996		73,996		—		—		—		—
11.0% Senior Secured Second Lien Notes due 2020(1)		—		—		1,450,000		587,250		1,398,896		1,276,000
8.25% Senior Notes due 2018(1)		—		—		213,677		28,633		539,459		306,000
6.875% Senior Notes due 2024(1)		—		—		143,993		16,559		650,000		211,250
3.0% Senior Convertible Notes due 2018(1)		—		—		363,018		1,472		354,218		94,000
7.5% Senior Notes due 2021(1)		—		—		238,071		25,807		500,000		164,925
7.75% Senior Notes due 2019(1)		—		—		101,077		9,875		250,000		92,135
9.25% Senior Notes due 2017(1)		—		—		249,452		25,943		750,000		413,160
Total	$	73,996	$	73,996	$	2,859,124	$	795,375	$	4,592,573	$	2,707,470

(1) In accordance with the Plan, on the Emergence Date, all outstanding obligations under these notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.

156

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 20 — Fair Value  – (continued)

The following table sets forth our Level 3 financial instruments (in thousands):

	Predecessor
	Six Months Ended December 31,		Year Ended June 30,
	2016		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

Note 21 — Prepayments and Accrued Liabilities

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

	Successor		Predecessor
	December 31,		June 30,
	2016		2016		2015
Prepaid expenses and other current assets
Advances to joint interest partners	$	650	$	974	$	1,294
Insurance		9,600		13,726		3,427
Inventory		470		423		7,867
Royalty deposit		1,273		2,168		3,137
Debt issuance costs		—		2,571		—
Other		13,964		9,166		8,573
Total prepaid expenses and other current assets	$	25,957	$	29,028	$	24,298
Accrued liabilities
Advances from joint interest partners		374		—		3,060
Employee benefits and payroll		4,491		7,377		18,927
Interest payable		233		—		83,384
Accrued hedge payable		—		—		1,399
Undistributed oil and gas proceeds		22,715		12,611		19,776
Severance taxes payable		628		619		843
Escrowed reorganization expenses		25,987		—		—
Other		9,232		19,821		27,917
Total accrued liabilities	$	63,660	$	40,428	$	155,306

157

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 22 — Comparative Period Information

The following tables present certain transition and comparative period financial information for the six month period ended December 31, 2016 and 2015, respectively.

	Predecessor
	Six Months Ended December 31,
	2016(1)			2015(2)
				(Unaudited)
	(In thousands)
Total Revenues	$	295,676		$	442,438
Operating loss		(82,029	)		(2,431,348	)
Income (loss) before income taxes		2,653,903			(1,883,924	)
Income tax expense (benefit)		—			51
Net Income (loss)	$	2,653,903		$	(1,883,975	)
Preferred stock dividends		—			5,664
Net Income (Loss) Attributable to Common Stockholders	$	2,653,903		$	(1,889,639	)
Earnings (Loss) per Share
Basic	$	26.99		$	(19.91	)
Diluted	$	25.33		$	(19.91	)
Weighted Average Number of Common Shares Outstanding
Basic		98,337			94,926
Diluted		104,787			94,926

	Predecessor
	Six Months Ended December 31,
	2016			2015
				(Unaudited)
	(In thousands)
Net cash used in operating activities	$	(17,473	)	$	(89,924	)
Net cash provided by (used in) investing activities		11,706			(82,872	)
Net cash used in financing activities		(32,123	)		(258,162	)
Net decrease in cash and cash equivalents	$	(37,890	)	$	(430,958	)

(1) Included in Operating income (loss) is impairment of oil and natural gas properties of $86.8 million and also included in Net income (loss) are reorganization items being gain on settlement of liabilities subject to compromise of $2,008.5 million, fair value adjustment of $830.5 and reorganization expenses of $90.6 million.

(2) Included in Operating income (loss) is impairment of oil and natural gas properties of $2,330.5 million and also included in Net income (loss) is gain on early extinguishment of debt of $748.6 million.

158

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 23 — Selected Quarterly Financial Data — Unaudited

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

	Predecessor
	Quarter Ended
	December 31,(7) 2016		September 30,(6) 2016			June 30,(2) 2016			March 31,(3) 2016			December 31,(4) 2015			September 30,(5) 2015
Revenues	$	153,065	$	142,611		$	147,804		$	116,285		$	184,615		$	257,823
Operating income (loss)		11,708		(93,737	)		(168,211	)		(417,866	)		(1,513,148	)		(918,200	)
Net income (loss)	$	2,785,049	$	(131,146	)	$	(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	$	2,785,049	$	(131,146	)	$	(195,904	)	$	158,398		$	(1,313,393	)	$	(576,246	)
Net income (loss) per share attributable to common stockholders(1)
Basic	$	28.17	$	(1.34	)	$	(2.01	)	$	1.65		$	(13.81	)	$	(6.08	)
Diluted		26.58		(1.34	)		(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 $142.6 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.

(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.

(6) Included in Operating income (loss) is impairment of oil and natural gas properties of $86.8 million and also included in Net income (loss) is reorganization expenses of $32.6 million.

(7) Included in Net income (loss) are reorganization items being gain on settlement of liabilities subject to compromise of $2,008.5 million, fair value adjustment gain of $830.5 and reorganization expenses of $58.0 million.

159

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 23 — Selected Quarterly Financial Data — Unaudited  – (continued)

	Predecessor
	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 24 — 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):

	Predecessor
	Six Months Ended December 31,		Year Ended June 30,
	2016		2016		2015		2014
Property acquisitions
Proved	$	1,500	$	26,400	$	—	$	2,046,879
Unevaluated		—		—		2,304		924,882
Exploration costs		—		1,400		38,183		153,136
Development costs		22,300		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 the costs are impaired, or (ii) ratably over a period of time of not more than four years. 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. However, following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development

160

ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24 — Supplementary Oil and Gas Information — Unaudited  – (continued)

drilling, recorded proved undeveloped reserves of 36.5 MMBOE at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million.

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 as of December 31, 2016 and audited by a third party reservoir engineering firm as of June 30, 2016, 2015, and 2014. 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 (Predecessor)		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 (Predecessor)		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	)
Sales of reserves		(9,901	)		(13,554	)		(12,160	)
Proved reserves at June 30, 2015 (Predecessor)		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 (Predecessor)		66,373			121,147			86,564
Production		(5,649	)		(13,485	)		(7,897	)
Extensions and discoveries		32,221			27,788			36,852
Revisions of previous estimates		5,453			5,788			6,418
Proved reserves at December 31, 2016 (Successor)		98,398			141,238			121,937

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24 — Supplementary Oil and Gas Information — Unaudited  – (continued)

	Oil (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed reserves
June 30, 2013 (Predecessor)		80,223		175,623		109,493
June 30, 2014 (Predecessor)		112,789		222,916		149,942
June 30, 2015 (Predecessor)		94,013		187,993		125,345
June 30, 2016 (Predecessor)		66,373		121,147		86,564
December 31, 2016 (Successor)		66,505		113,603		85,439
Proved undeveloped reserves
June 30, 2013 (Predecessor)		53,424		93,498		69,007
June 30, 2014 (Predecessor)		72,600		141,940		96,256
June 30, 2015 (Predecessor)		43,059		90,550		58,151
June 30, 2016 (Predecessor)		—		—		—
December 31, 2016 (Successor)		31,892		27,635		36,498

Our proved reserves increased by 35.4 MMBOE or by approximately 41% from 86.6 MMBOE at June 30, 2016 to 121.9 MMBOE as of December 31, 2016. The increase was primarily due to:

• The booking of 36.5 MMBOE of Proved Undeveloped reserves (included in extensions and discoveries above). These reserves had been previously recorded by EXXI Ltd and then subsequently removed by it in the December 31, 2015 quarter due to the uncertainty regarding its ability to secure the required development financing prior to the restructuring of the its debt; and

• Upward revisions of approximately 6.4 MMBOE of proved reserves resulting primarily from the extension in field life due to the addition of proved undeveloped reserves

These were offset by:

• 7.9 MMBOE of production during the period.

Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows as of December 31, 2016 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $42.74 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 December 31, 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 $41.51 per barrel of oil and $21.63 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. The $41.51 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $42.74 per barrel (differential of $1.23 per barrel).

For natural gas, the average Henry Hub price used was $2.48 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 $2.29 per MMBtu after adjusting for energy content, transportation fees, and regional price differentials.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24 — Supplementary Oil and Gas Information — Unaudited  – (continued)

The standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves follows (in thousands):

				Predecessor
	As of December 31,			As of June 30,
	2016			2016			2015		2014
Future cash inflows	$	4,344,985		$	2,966,317		$	10,641,151	$	20,162,506
Less related future
Production costs		2,648,363			2,223,645			4,131,526		5,500,669
Development and abandonment costs		1,587,527			1,033,717			1,970,526		2,959,994
Income taxes		—			—			168,655		2,546,155
Future net cash flows		109,095			(291,045	)		4,370,444		9,155,688
Less: Ten percent annual discount for estimated timing of cash flows		(26,315	)		(349,398	)		1,613,034		3,208,163
Standardized measure of discounted future net cash flows (Predecessor)				$	58,353		$	2,757,410	$	5,947,525
Standardized measure of discounted future net cash flows (Successor)	$	135,410

The increase in our proved reserves had a significant impact on our estimated standardized measure values of the proved reserves which increased from approximately $58.4 million as of June 30, 2016 to approximately $135.4 million as of December 31, 2016, mainly due to the following:

• The booking of 36.5 MMBOE of proved undeveloped reserves from contingent resource category, and

• The increase in proved developed reserves value resulting from greater economic field life due to the booking of proved undeveloped reserves and the delay of significant abandonment costs for all fields.

The discounted PV-10 of the properties as of December 31, 2016 and June 30, 2016 are higher than the undiscounted value due to the projected significant plugging and abandonment activity at the end of the life of the properties that are heavily discounted.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24 — 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):

	Predecessor
	Six Months Ended December 31,			Year Ended June 30,
	2016			2016			2015			2014
Beginning of period (Predecessor)	$	58,353		$	2,757,410		$	5,947,525		$	4,481,522
Revisions of previous estimates
Changes in prices and costs		(104,993	)		(3,287,459	)		(2,959,883	)		(196,159	)
Changes in quantities		53,585			(214,631	)		(2,390,099	)		(389,570	)
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		325,892			26,911			201,234			533,133
Purchases (sales) of reserves in place		—			212,961			(244,507	)		1,735,957
Accretion of discount		(893	)		215,297			760,175			614,964
Sales, net of production and gathering and transportation costs		(131,947	)		(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		(2,704	)		4,189			(191,668	)		(253,290	)
Development costs incurred		11,283			10,493			237,173			247,865
Changes in estimated future development and abandonment costs		(73,166	)		468,738			497,455			(5,012	)
Net change		77,057			(2,699,057	)		(3,190,115	)		1,466,003
End of period (Predecessor)				$	58,353		$	2,757,410		$	5,947,525
End of period (Successor)	$	135,410

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

As previously reported in EXXI Ltd’s Current Report on Form 8-K filed on December 4, 2014, on December 1, 2014, UHY LLP (“UHY”) informed EXXI Ltd 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 Predecessor 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 Predecessor Company (the “Predecessor Audit Committee”) had selected UHY to serve as the Predecessor Company’s independent registered public accounting firm for the fiscal year ending June 30, 2015. In addition, the shareholders of the Predecessor Company approved and ratified that appointment at the Predecessor Company’s Annual General Meeting on November 14, 2014.

During the Predecessor Company’s two most recent fiscal years, previous to the acquisition of the UHY Texas practice by BDO, UHY’s audit reports on the Predecessor 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 Predecessor Company’s two most recent fiscal years of BDO acquiring the UHY Texas practice and the subsequent interim period through the Resignation Date, the Predecessor 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 Predecessor 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 Predecessor 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 Predecessor 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 Predecessor Company’s fiscal years ended June 30, 2014 and 2013 and during any subsequent interim period through the Resignation Date, did the Predecessor 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 Predecessor 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 Predecessor 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 interim Chief Executive Officer and interim 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.

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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 87 and is incorporated herein by reference.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our quarterly period ended December 31, 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

Board of Directors

The following sets forth information concerning each member of our reconstituted Board of Directors (the “Board of Directors” or the “Board”) as of February 20, 2017, including their name, age, principal occupation or employment for at least the past five years and the period for which such person has served as a director of the Company. There are no family relationships among any of our directors or executive officers or arrangements or understandings between any of our directors and any other person pursuant to which any person was selected as a director.

Director	Position(s)	Age as of February 20, 2017
Michael S. Bahorich	Director	60
George Kollitides	Director	47
Steven Pully	Director	56
Michael S. Reddin	Chairman	56
James “Jay” W. Swent III	Director	66
Charles W. Wampler	Director	62

Michael S. Bahorich is an award-winning oil and gas executive with broad technical knowledge, deep industry expertise, and experience serving on both corporate and non-profit boards. Skilled in managing operations, research, and technical service at major and independent oil companies, Mr. Bahorich recently retired from Apache Corporation where he served as an executive vice president for 15 years, most recently as Chief Technology Officer. Prior to joining Apache, Mr. Bahorich worked at Amoco Corporation, which he joined in 1981 as a Geoscientist. He has a B.S. in Geology from the University of Missouri, Columbia, and an M.S. in Geophysics from Virginia Polytechnic Institute (VPI). Mr. Bahorich previously served as a director of Global Geophysical Services. His advisory experience with non-profit organizations includes serving as a trustee of the Houston Museum of Natural Science and as a member of academic advisory boards at both Yale and Stanford Universities. The Board believes that Mr. Bahorich is qualified to serve on the Board based on his experience, education and technical knowledge as a geophysicist and senior executive with 35 years’ experience in the oil and gas industry.

George Kollitides is an experienced transaction, strategy and operations leader who has held principal, board and operational leadership roles in public, private and non-profit organizations. He is currently a Managing Director, Investment Committee member, and co-head of A&M Capital Opportunities (“AMCO”). Prior to joining AMCO, Mr. Kollitides was Chairman and CEO of the Remington Outdoor Company and a Managing Director at Cerberus Capital Management, L.P. (“Cerberus”). Prior to Cerberus, Mr. Kollitides was the co-founder of TenX Capital Management (“TenX”), a special situations private equity firm, and a Principal at Catterton Partners. Mr. Kollitides started his career at GE, where he was six sigma trained and

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focused on turning around under-performing businesses, leveraged finance and private equity. Mr. Kollitides currently serves as a director on the Boards of adMarketplace, Precision Gear, Inc. and Tier 1 Group. He also serves as the Vice Chairman of the Orthopedic Foundation for Active Lifestyles and is a NY Advisory Board Member for Good Sports. Mr. Kollitides received an MBA in Finance and Management of Organizations from Columbia Business School in 1998 and a BA in Economics with a Minor in Government and Law from Lafayette College in 1991. The Board believes that Mr. Kollitides is qualified to serve on the Board based on his education and senior executive experience in business operations, asset management, risk management, and strategic planning.

Steven Pully provides consulting and investment banking services for companies and investors focused on the oil and gas sector, and has extensive experience serving on the boards of both public and private companies. From 2008 until 2014, Mr. Pully served as General Counsel and Partner of the investment firm Carlson Capital, L.P. Mr. Pully was also previously a Senior Managing Director at Bear Stearns and a Managing Director at Bank of America Securities. Mr. Pully is currently a director of two public companies in addition to Energy XXI, Bellatrix Exploration and VAALCO Energy, and two private boards. Mr. Pully was also a director of EPL Oil & Gas for the six years prior to the sale of the company to Energy XXI Ltd in June 2014 and served as lead independent director at the time of the sale. Mr. Pully is a Chartered Financial Analyst, a Certified Public Accountant in the State of Texas and a member of the State Bar of Texas. Mr. Pully earned his undergraduate degree in Accounting from Georgetown University and is also a graduate of The University of Texas School of Law. The Board believes that Mr. Pully is qualified to serve on the Board based on his education, professional expertise, and experience serving on the boards of numerous exploration and production companies as well as his capital markets, merger and acquisition, governance and legal experience.

Michael S. Reddin has over 34 years of upstream oil and gas experience in North America, having served in a wide variety of engineering, commercial and leadership roles with small, medium, and large companies. From August 2009 to April 2016, Mr. Reddin served as President and CEO of Davis Petroleum Acquisition Corp., where he also served as Chairman of the Board for the last three years. In this role, Mr. Reddin led the sale of Davis’ offshore business to another offshore operator and the merger of its onshore business with Yuma Energy, Inc. Prior to joining Davis, Mr. Reddin served as President and CEO of Kerogen Resources, Inc., Vice President of BP America’s Deepwater Gulf of Mexico Business Unit, and in various other technical, commercial and leadership roles with BP, Vastar Resources, and ARCO. Mr. Reddin currently serves on the Board of Southcross Holdings GP LLC and Midstates Petroleum Company, and previously served on the Boards of Berry Petroleum Company, Gulfport Energy, Kerogen Resources, Davis Petroleum, and several non-profit organizations. Mr. Reddin earned his BS in Mechanical Engineering from Texas A&M University. The Board believes that Mr. Reddin is qualified to serve as Chairman of the Board based on his education and extensive experience as a senior leader and board member for various companies in the oil and gas industry.

James “Jay” W. Swent III is a proven business leader with over 35 years of experience working in North America, Europe, Asia, and Latin America. From July 2003 to December 2015, Mr. Swent served as Chief Financial Officer of Ensco plc, and as additionally as Executive Vice President from July 2012 to December 2015. Prior to that, Mr. Swent held senior leadership positions in general management, operations, finance and business development in a diverse range of industries with companies such as Memorex Telex, Rodime, Nortel, Cyrix, and American Pad and Paper. He has served on Boards of public companies listed on the NYSE, NASDAQ, and London Stock Exchange. Mr. Swent earned both a Master of Business Administration in Finance and a Bachelor of Science degree from the University of California, Berkeley. The Board believes that Mr. Swent is qualified to serve as Lead Independent Director on the Board based on his education and experience as a senior executive, including as Chief Executive Officer and Chief Financial Officer of a public company, his finance and accounting expertise, as well as significant experience with mergers and acquisitions.

Charles W. Wampler is an extensively experienced oil and gas operations executive who currently serves on the boards of two oil and gas companies, including Energy XXI. From 2007 to 2016, Mr. Wampler held roles as Chief Operating Officer of Aspect Holdings, President of Aspect Energy and General Exploration Partners (“GEP”), where he also served as a Board member from 2009 to 2012. Mr. Wampler directed the

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day to day management of Aspect’s domestic operations in the US Gulf Coast and international operations in Hungary and Kurdistan, Iraq. Prior to joining Aspect, Mr. Wampler was a Board member and Chief Operating Officer for Lewis Energy Group, where he directed the company’s domestic exploration and production activities while also overseeing international drilling, production, and pipeline operations in Mexico and Colombia. Mr. Wampler’s previous experience includes serving as Division Operations Manager and Drilling Manager of EOG Resources and several engineering positions with Valero Producing Company and Kerr-McGee. Mr. Wampler currently serves as a director for Swift Energy Company. Mr. Wampler earned his BS in Petroleum Engineering from the University of Southwestern Louisiana. The Board believes that Mr. Wampler is qualified to serve on the Board based on his education and several decades of oil and gas industry experience in general management roles with an emphasis on operations leadership.

Committees of Our Board of Directors

Our Board currently has an Audit Committee, a Nomination and Governance Committee and a Compensation Committee.

Director	Audit	Nomination and Governance	Compensation
Michael S. Bahorich	—	M	M
George Kollitides	M	M	M
Steven Pully	M	M	C
Michael S. Reddin	—	—	—
James “Jay” W. Swent III	C	—	M
Charles W. Wampler	M	C	—

C = Chairman M = Member

Audit Committee

The Company’s Audit Committee oversees the accounting and financial reporting processes of the Company and the audits of the Company’s financial statements by assisting the Board in monitoring (i) the integrity of the financial statements of the Company, (ii) the independent auditor’s qualifications and independence, (iii) the performance of the Company’s internal audit function and independent auditors, and (iv) the compliance by the Company with legal and regulatory requirements. The Audit Committee is composed of Messrs. Swent (who serves as its chair), Kollitides, Pully and Wampler, each of whom is an independent director under Rule 10A-3 under the Exchange Act and the NASDAQ Listing Standard. Our Board also has determined that each member of the Audit Committee is financially literate and that Mr. Swent has the necessary accounting and financial expertise to serve as chair. Further, our Board has determined that Mr. Swent is an “audit committee financial expert” following a determination that Mr. Swent met the criteria for such designation under the SEC’s rules and regulations.

The Audit Committee operates under a written charter adopted by our Board, a current copy of which is available on our website at www.energyxxi.com under “Corporate Governance.”

The Audit Committee recommends the annual appointment of our independent registered public accounting firm with whom the Audit Committee reviews the scope of audit and non-audit assignments and related fees, and reviews accounting principles we will use in financial reporting, internal auditing procedures and the adequacy of our internal control procedures.

Compensation Committee

The Company’s Compensation Committee establishes salaries, incentives and other forms of compensation for executive officers. The Compensation Committee also administers the Company’s incentive compensation and benefit plans. The Company’s Compensation Committee is composed of Messrs. Pully (who serves as its chair), Bahorich, Kollitides and Swent.

The Compensation Committee operates under a written charter adopted by our Board, a current copy of which is available on our website at www.energyxxi.com under “Corporate Governance.”

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The Compensation Committee evaluates the performance of our officers, reviews overall management compensation and benefits policies, and reviews and recommends employee benefits plans, options and/or restricted share grants and other incentive arrangements.

Nomination and Governance Committee

The Company’s Nomination and Governance Committee identifies, evaluates and recommends qualified nominees to serve on the Company’s Board, develops and oversees the Company’s internal corporate governance processes and the Board’s composition and committee membership. The Nomination and Governance Committee is composed of Messrs. Wampler (who serves as its chair), Bahorich, Pully and Kollitides, all of whom are independent under the NASDAQ Listing Standards. Mr. Reddin previously served on the Nomination and Governance Committee, but he resigned upon his appointment as Interim CEO and President effective February 2, 2017 and replaced by Mr. Kollitides.

The Nomination and Governance Committee operates under a written charter adopted by our Board, a current copy of which is available on our website at www.energyxxi.com under “Corporate Governance.”

The primary purposes of the Nomination and Governance Committee are to: identify individuals qualified to become members of our Board and recommend such individuals to our Board for nomination for election, make recommendations to our Board concerning committee appointments and provide oversight of the corporate governance affairs of our Board and our Company.

Director Nomination Process

Our Nomination and Governance Committee has a policy of considering candidates for director, including those candidates recommended by our shareholders. The Nomination and Governance Committee reviews candidates based on general criteria it has established for membership on our Board, including, among other things, such candidates’ integrity, independence, diversity of experience and leadership. Our Nomination and Governance Committee uses the same processes in evaluating nominations for our Board, irrespective of whether the nomination is made by a shareholder or by a member of our Board.

Although our Nomination and Governance Committee has not established any fixed qualifications for an acceptable nominee to our Board, our Nomination and Governance Committee believes our directors should possess the highest personal and professional ethics, integrity and values, be committed to representing the long-term interests of our shareholders and be willing and able to devote sufficient time to carrying out their duties and responsibilities effectively. In addition, our directors should be committed to serve on our Board for an extended period of time and should not serve on the boards of business entities competitive with us, or on the board of directors of more than three public companies, unless doing so would not impair the director’s service on our Board. While the Board does not have a formal policy on diversity, the Board seeks candidates who, in addition to providing a range of talents and expertise, are sufficiently diverse as to provide a range of perspectives representative of the interests of constituencies served or to be considered from time to time by the Board of Directors, including our shareholders and our employees. Our Nomination and Governance Committee does not have a formal process for identifying and evaluating nominees for directors, but rather uses its network of contacts to identify and evaluate potential candidates.

Any shareholder desiring to nominate qualified candidates for election as a director to our Board must submit to our Corporate Secretary a notice, executed by such shareholder (not being the person proposed as a candidate) prior to a contemplated annual general meeting and received no fewer than 90 nor more than 120 days prior to the first anniversary of the immediately preceding annual meeting, of the intention to propose such candidate. The notice must set forth as to each person whom the shareholder proposes to nominate for director:

• the name, age, business address and residence address of such person;

• the principal occupation or employment of such person;

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• the class, series and number of shares of the Company’s common stock beneficially owned by such person; and

• all other information relating to such person that is required to be disclosed in solicitations for proxies for the election of directors pursuant to the rules and regulations of the SEC under Section 14 of the Exchange Act.

Director Compensation

We believe that it is important to attract and retain outstanding non-employee directors, and one way that we believe we can achieve this goal is to offer compensation and incentives for such service. Directors who are our employees or employees of any of our subsidiaries receive no additional compensation for their services as directors.

None of our non-employee directors received compensation for services provided during our transition period from July 1, 2016 to December 31, 2016. A description of the compensation of Mr. Schiller, who was an employee director of the Company, is separately provided in this Form 10-K under “Executive Compensation.”

Name	Fees Earned or Paid in Cash ($)		Stock and Unit Awards ($)		All Other Compensation ($)		Total ($)
William Colvin(1)	$	106,500	$	—	$	—	$	106,500
Cornelius Dupré II(1)		95,500		—		—		95,500
Hill A. Feinberg(1)		81,500		—		—		81,500
Kevin Flannery(1)		96,500		—		—		96,500
Scott A. Griffiths(1)		89,500		—		—		89,500
James LaChance(1)		80,000		—		—		80,000
Michael S. Bahonrich(2)		—		—		—		—
George Kollitides(2)		—		—		—		—
Steven Pully(2)		—		—		—		—
Michael S. Reddin(2)		—		—		—		—
James “Jay” W. Swent III(2)		—		—		—		—
Charles W. Wampler(2)		—		—		—		—

(1) Pursuant to the Plan, as of the Emergence Date, these directors resigned from EXXI Ltd’s board of directors. Following the resignation of all of the directors of EXXI Ltd and in accordance with Bermuda law, the Provisional Liquidator assumed full control of EXXI Ltd’s affairs and will continue to do so until the conclusion of the Bermuda Proceeding.

(2) On the Emergence Date, by operation of the Plan, these individuals became members of our board of directors.

The Board of Directors of EXXI Ltd (the “Predecessor Board”) previously adopted the Energy XXI Services, LLC Directors’ Deferred Compensation Plan (the “Directors’ Deferred Compensation Plan”). Under the Directors’ Deferred Compensation Plan, non-employee directors may elect to defer all or a portion of their cash and equity compensation. Payment will be made within 30 days following the director’s separation from service or on another date selected by the director. Payment is made in a lump sum in either cash or shares of common stock depending on the type of compensation that was deferred by the director.

In connection with our emergence from the Chapter 11 Cases, the Directors’ Deferred Compensation Plan was terminated. During the transition period from July 1, 2016 to December 31, 2016, there were no deferrals and no distributions under the Directors’ Deferred Compensation Plan.

In July 2015, the Compensation Committee of the Predecessor Board (the “Predecessor Compensation Committee”) reviewed the director compensation program for fiscal year 2016. After its review of director compensation, the committee elected to reduce the equity retainer paid to directors by 50%, from $175,000 to $87,500. These changes were made in light of the market environment and in order to help manage

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shareholder dilution at the time that the Predecessor Compensation Committee set director compensation. Furthermore, beginning with the second quarter of fiscal year 2016, the lead EXXI Ltd independent director no longer received any additional cash, equity or other compensation for serving in such capacity. This change was made in light of the appointment of a Chairman of the Predecessor Board in October 2015 who was separate from EXXI Ltd’s Chief Executive Officer, which resulted in fewer additional duties for the lead independent director. This program was continued through the transition period.

On January 6, 2017, the Board adopted the Non-Employee Director Compensation Policy (the “Director Compensation Policy”), pursuant to which each non-employee director is entitled to receive, or has received, the compensation as set forth in the Director Compensation Policy. The Director Compensation Policy provides for annual cash retainers of (i) $75,000 for serving on the Board or $125,000 for serving as the Non-Executive Chairman of the Board; (ii) $25,000 for serving as the Chairman of the Audit Committee and $12,500 for serving as a member of the Audit Committee; (iii) $25,000 for serving as the Chairman of the Compensation Committee and $12,500 for serving as a member of the Compensation Committee; and (iv) $10,000 for serving as the Chairman of the Nomination and Governance Committee and $5,000 for serving as a member of the Nomination and Governance Committee. As set forth in the Director Compensation Policy, each non-employee director is also eligible to receive (a) an initial restricted stock unit award of $200,000 or $300,000 for the Non-Executive Chairman of the Board and (b) $130,000 of annual restricted stock units or $175,000 for the Non-Executive Chairman of the Board. The deemed value utilized by the Board for purposes of the equity awards granted in January 2017 pursuant to the Director Compensation Policy was $20 per share. All equity awards granted pursuant to the Director Compensation Policy are subject to the terms and conditions of the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), to such director’s continued service on the Board, and to acceleration upon the occurrence of specified events.

Awards of restricted stock units made pursuant to the Director Compensation Policy may be deferred in a non-qualified deferred compensation plan pursuant to which a director may defer the settlement of restricted stock units. The deferral election will allow a director to defer the receipt and taxation of the common stock issuable pursuant to the awards past the otherwise applicable vesting date to the earlier to occur of (i) a change of control (as defined in the 2016 LTIP) or (ii) the director’s separation from service with us and our subsidiaries for any reason (provided, in each case, the restricted stock units are vested).

On January 17, 2017, we made annual awards of restricted stock units to our non-employee directors in accordance with the terms of the Director Compensation Policy in the amount of 15,000 restricted stock units to Mr. Reddin and 10,000 to Messrs. Bahonrich, Kollitides, Pully, Swent and Wampler (the “Initial Grant”). The Initial Grants vest in three equal installments on January 31, 2018, December 31, 2018 and December 31, 2019 unless deferred as described above. On January 17, 2017, we also made initial awards to our non-employee directors in accordance with the Director Compensation Policy in the amount of 8,750 restricted stock units to Mr. Reddin and 6,500 restricted stock units to Messrs. Bahonrich, Kollitides, Pully, Swent and Wampler (the “Annual Grant”). One-half of the Annual Grants vested on the date of grant and one-half will vest on January 31, 2018 unless deferred as described above.

Corporate Governance

We maintain a corporate governance page on our website, which includes information about our Code of Business Conduct and Ethics and charters for each of the committees of our Board: the Audit Committee, the Compensation Committee and the Nomination and Governance Committee. The corporate governance page can be found at www.energyxxi.com, by clicking on “Leadership” and then on “Corporate Governance.”

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Code of Business Conduct and Ethics

We have adopted EXXI Ltd’s Code of Business Conduct and Ethics as our “code of ethics” as defined by regulations promulgated under the Securities Act of 1933, as amended (the “Securities Act”) and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which applies to all of our directors, officers and employees, including our chief executive officer, chief financial officer, chief accounting officer and controller. A current copy of the Code of Business Conduct and Ethics is available at the “Corporate Governance” section of our website at www.energyxxi.com under “Corporate Governance.” A copy of our Code of Business Conduct and Ethics may also be obtained free of charge upon a request directed to:

Energy XXI Gulf Coast, Inc.
c/o Investor Relations
1021 Main Street, Suite 2626
Houston, Texas 77002

We will promptly disclose any substantive changes in or waivers, along with reasons for the waivers, of the Code of Business Conduct and Ethics by posting such information on our website at www.energyxxi.com under “Investor Relations” and “Corporate Governance.”

Our Code of Business Conduct and Ethics includes, among other things, (a) an express prohibition on personal loans from the Company’s vendors in (other than ordinary course loans from financial institutions), (b) procedures for soliciting or accepting charitable contributions from entities doing business with the Company, (c) clarifying the precise procedures for reporting potential conflicts of interest and requesting waivers, and (d) independent oversight from a chief compliance officer (the “Chief Compliance Officer”) and, in the case of executive officers and directors, the Audit Committee. The Chief Compliance Officer works with the Company’s senior management and the Board to instill a culture of compliance and encourage all employees, officers and Directors to take compliance issues seriously. In this regard, the Chief Compliance Officer is also responsible for implementing a Company-wide training program with respect to each of the three policies.

Related Party Transactions Policy

The Board has adopted a Related Party Transaction Policy as part of the Code of Business Conduct and Ethics. For more information, please read Item 13. “Certain Relationships and Related Transactions, and Director Independence.”

Vendor Procurement Policies

The Board has adopted a Vendor Procurement Policy to provide enhanced scrutiny from the Chief Compliance Officer and the Audit Committee of instances in which there is even the appearance of a conflict of interest between the Company and any of its vendors. Among other things, in such instances, competitive bids are required absent an emergency and the Chief Compliance Officer must review and approve the terms of the proposed arrangement, including the proposed scope of work and compensation to be paid to the vendor. The Audit Committee must be copied on any such approval.

Risk Management

The Board has adopted an Energy Risk Management Policy to minimize the Company’s exposure to certain risks. The risk management committee, a committee comprised of certain of the Company’s officers, reviews, evaluates and discusses the Company’s risk management processes, engaging in open communication with the Board.

Insider Trading Policy

The Company has adopted an Insider Trading Policy prohibiting the pledging and hedging of the Company’s securities by directors, officers, and employees (as well as the immediate family members of any such individual). The Insider Trading Policy also includes, among other things, (a) express prohibitions on pledges and margin loans relating to the Company’s securities and (b) express prohibitions on hedging transactions and short sales related to the Company’s securities.

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Executive Officers

The following table sets forth the name, age and positions of our executive officers:

	Position		Age as of February 20, 2017
Michael S. Reddin		Chairman of the Board and Interim Chief Executive Officer and President		56
Hugh A. Menown		Executive Vice President, Interim Chief Financial Officer and Chief Accounting Officer		58
Scott M. Heck		Chief Operating Officer		59

Hugh A. Menown has served as Executive Vice President, Interim Chief Financial Officer and Chief Accounting Officer of Energy XXI since February 2017 and as Executive Vice President, Chief Accounting Officer of Energy XXI since May 2007. Previously, he served as Chief Information Officer of Energy XXI from July 2010 to October 2014, and he served as Senior Vice President from July 2010 until June 2014 when he was promoted to Executive Vice President. From August 2006 until his appointment as our Chief Accounting Officer, Mr. Menown worked for Energy XXI as an independent consultant, working for the first seven months of 2006 as an independent consultant in the energy industry. From March 2002 until December 2005 Mr. Menown was employed by Quanta Services, Inc., serving as Chief Financial Officer of two of its subsidiaries. From 1987 to 1999, Mr. Menown provided audit and related services for clients at PricewaterhouseCoopers, LLP in the Houston office, where for seven years he was the partner in charge of the transaction services practice providing due diligence, mergers and acquisition advisory and strategic consulting to numerous clients in various industries. Mr. Menown has more than 35 years of experience in mergers and acquisitions, auditing and managerial finance, is a certified public accountant and a 1980 graduate of the University of Missouri-Columbia with a bachelor’s degree in business administration.

Scott M. Heck has served as Chief Operating Officer of the Company since February 2, 2017. Mr. Heck has over 36 years of experience in upstream oil and gas engineering and leadership roles with Tenneco Oil Company, Hess E&P, and most recently at Bennu Oil & Gas LLC (“Bennu”), the last 14 years of which have been in senior executive roles with extensive offshore accountabilities. He served as Bennu’s Chief Operating Officer from February 2014 until November 2016, overseeing all exploration and production operations and support services, reporting to Bennu’s chief executive officer. Mr. Heck joined Bennu directly from Hess, where he had worked since June 1989 and had held executive positions of increasing seniority and responsibility since 2005. At Hess, Mr. Heck served as Senior Vice President-Global Offshore Exploration and Production from 2013 to February 2014, Senior Vice President-Global Offshore Exploration from 2012 to 2013, Senior Vice President-E&P Technology from 2007 to 2013, and Senior Vice President-Americas & West Africa Production from 2005 to 2007. He is a graduate of the Marietta College with a bachelor’s degree in Petroleum Engineering.

Biographical information about Michael S. Reddin is included above under the heading “— Board of Directors.”

Section 16(A) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act and related rules of the SEC require our directors and Section 16 officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the SEC. These persons are required by SEC regulations to furnish us with copies of all Section 16(a) reports that they file. We assist our directors and executive officers in making their Section 16(a) filings pursuant to powers of attorney granted by our insiders on the basis of information obtained from them and our records.

Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to the Company during the transition period ended December 31, 2016, including those reports that we have filed on behalf of our directors and Section 16 officers pursuant to powers of attorney, no director, Section 16 officer, beneficial owner of more than 10% of the outstanding common stock of the company, or any other person subject to Section 16 of the Exchange Act, failed to file on a timely basis during such transition period.

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Involvement in Certain Legal Proceedings

On June 17, 2016, the SEC filed a proof of claim against EXXI Ltd asserting a general unsecured claim in the amount of $3.9 million based on alleged violations of the federal securities laws by EXXI Ltd pertaining to the failure to disclose certain funds borrowed by our former President and CEO John D. Schiller, Jr. from personal acquaintances or their affiliates, certain of whom provided EXXI Ltd and certain of its subsidiaries with services and Mr. Schiller’s pledge of EXXI Ltd stock to a certain financial institution in the second half of 2014. The claim has been classified as a general unsecured claim subject to a cap of approximately $1.4 million, which will be paid by EGC, under the Plan and will 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.

Item 11. Executive Compensation

On April 14, 2016, Energy XXI Ltd and the other Debtors filed the Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. Following the filing, EXXI Ltd continued to operate its business as a “debtor in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

On December 30, 2016 (the “Emergence Date”), the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and we and the other Reorganized Debtors emerged from the Chapter 11 Cases. In connection with the satisfaction of the conditions to effectiveness as set forth in the Confirmation Order and in the Plan, we completed a series of internal reorganization transactions together with EXXI Ltd pursuant to which EXXI Ltd transferred substantially all of its remaining assets to reorganized us, as the new parent entity, and, accordingly, we succeeded to the entire business and operations previously consolidated for accounting purposes at EXXI Ltd.

Our named executive officers (the “Named Executive Officers” or “NEOs”), like our employees generally and our shareholders and other stakeholders, have been significantly impacted by the Chapter 11 Cases. The information presented in this Compensation Discussion and Analysis (this “CD&A”) reflects compensation for our NEOs for the transition period from July 1, 2016 through December 31, 2016. As a result of the Plan, there are no assets remaining in EXXI Ltd, and, under Bermuda law, shareholders (including preferred shareholders) of EXXI Ltd will receive no payments. EXXI Ltd will be dissolved at the conclusion of the Bermuda Proceeding, and as such, the shareholders will no longer have any interest in EXXI Ltd as a matter of Bermuda law. Therefore, our NEOs will not receive any value on account of their stock options, restricted stock units, performance units or any other equity holdings in their shares of EXXI Ltd common stock despite the values reflected in this CD&A.

Compensation Discussion and Analysis

The analysis set forth below explains our compensation programs, as well as the objectives and rationales for the various elements of our compensation, for our “Named Executive Officers”:

• Mr. John D. Schiller, Jr., former President and Chief Executive Officer.

• Mr. Bruce W. Busmire, former Chief Financial Officer.

• Mr. Hugh Menown, Executive Vice President, Interim Chief Financial Officer and Chief Accounting Officer.

• Mr. Antonio de Pinho, former Chief Operating Officer.

This discussion is organized as follows:

• Part I: Executive Summary — discusses our overall approach to compensation and the factors that contributed to setting our compensation, including for the transition period from July 1, 2016 through December 31, 2016 and a brief summary of compensation for the fiscal year ended December 31, 2017.

• Part II: Elements of Compensation — analyzes the components of our Named Executive Officers’ compensation.

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• Part III: Factors for Determining Transition Period Compensation — reviews the factors in determining compensation for the transition period from July 1, 2016 to December 31, 2016 for our Named Executive Officers.

• Part IV: Roles of Contributors to our Compensation Program — reviews the participants and tools that help us make compensation decisions.

• Part V: Material Tax and Accounting Considerations — discusses various regulatory matters that contribute to our compensation decisions.

Part I: Executive Summary

2015 Say on Pay Vote

EXXI Ltd shareholders were given an opportunity to vote on our executive compensation program in connection with the 2015 EXXI Ltd Annual General Meeting of Shareholders. In 2015, the EXXI Ltd shareholders voted to approve, on a non-binding advisory basis, the compensation of our named executive officers, as set forth below. In a non-binding advisory vote regarding the frequency at which shareholder approval of our executive compensation arrangements would be sought, shareholders also voted in favor of annual approval, as set forth below.

NON-BINDING ADVISORY VOTE TO APPROVE NAMED EXECUTIVE OFFICERS’ COMPENSATION

	Votes For		Votes Against		Abstain		Broker Non-Votes
		21,409,658		2,847,100		6,268,373		47,372,978

NON-BINDING ADVISORY VOTE TO APPROVE THE FREQUENCY OF FUTURE ADVISORY VOTES ON THE COMPENSATION OF NAMED EXECUTIVE OFFICERS

	One Year		Two Years		Three Years		Abstain		Broker Non-Votes
		21,087,588		326,956		2,616,970		6,493,617		47,372,978

Changes to Executive Compensation Programs

In light of our Predecessor’s stock price and the market environment at the time that the Predecessor Compensation Committee set executive compensation for fiscal year 2016, the Predecessor Compensation Committee took the following actions related to fiscal 2016 executive compensation, which decisions were not revised during the transition period:

• Reduced 2016 long-term incentive (“LTI”) target values by 60%;

• Gave no base salary increases to executives for the 2016 fiscal year;

• Added Absolute Total Shareholder Return and net debt reduction milestones for the Company’s 2016 LTI program;

• Changed the frequency of the say-on-pay vote from triennial to annual, beginning in 2015, to enhance shareholder communication process related to executive compensation;

Executive Summary of Compensation Programs

The offshore oil and gas industry is strongly influenced by the factors shown below that significantly affect strategic decision making and Company performance over time. Recruiting, hiring and retaining executives who understand and can evaluate this environment is also key to our success. These factors include:

• complex technical expertise;

• overarching effect of world oil markets;

• large concentrated capital investments with long payback horizons;

• hiring needs for employees with highly specialized skills sets;

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• cyclical nature of oil and gas demand and pricing; and

• laws, regulations, customs, safety and environmental considerations that can have significant impact on results.

These factors also influence how we design and administer our executive pay programs to aim to be competitive and drive superior company performance. Most notably, these influences are seen in the following:

• our annual incentive plan design, which includes strategic financial and operational measures; and

• our use of both time-based and performance-based long-term incentives.

What We Do	What We Don’t Do
Award annual incentive compensation and the majority of long-term compensation subject to achievement of pre-established performance goals	Provide excise tax gross-ups to future executives Allow repricing of underwater stock options   without shareholder approval
Use an independent compensation consultant	Provide excessive perquisites
Review executive compensation tally sheets
Perform an annual risk assessment of our executive compensation programs

Transition Period Compensation

Compensation with respect to salary and employee benefits for NEOs for the transition period remained the same as fiscal year June 30, 2016.

In accordance with the Plan, prior to the Emergence Date, the following officers of EXXI Ltd were appointed as our officers:

Name	Offices
John D. Schiller, Jr.	Chief Executive Officer and President
Bruce W. Busmire	Chief Financial Officer
Antonio de Pinho	Chief Operating Officer
Hugh Menown	Executive Vice President, Chief Accounting Officer

Compensation Changes Occurring After December 30, 2016

Departure of John D. Schiller, Jr.

On February 2, 2017, John D. Schiller, Jr. ceased to serve as our President and Chief Executive Officer and also ceased to serve as a member of the Board. In connection with his termination of employment, the employment-related provisions of his Executive Employment Agreement, dated as of December 30, 2016 (the “Schiller Employment Agreement”) were terminated as of February 2, 2017. Under the Schiller Employment Agreement, Mr. Schiller is entitled to receive the following benefits, subject to his entry into a waiver and release agreement (i) a lump-sum cash severance payment in the amount of $2 million, and (ii) reimbursement for the monthly cost of maintaining health benefits for Mr. Schiller and his spouse and eligible dependents as of the date of his termination for a period of 18 months to the extent Mr. Schiller elects COBRA continuation coverage, less applicable taxes and withholding. The $2 million cash severance payment is payable on April 3, 2017, the 60^th day after the termination date. Those payments and benefits are subject to Mr. Schiller’s continued compliance with certain confidentiality, non-competition, non-solicitation and non-disparagement provisions of the waiver and release agreement.

On February 2, 2017, we entered into a consulting agreement (the “Schiller Consulting Agreement”) with Mr. Schiller, pursuant to which Mr. Schiller has agreed to serve as a special advisor to the Board during a transition period of up to six months. In consideration for those services, we have agreed to pay Mr. Schiller a consulting fee equal to $50,000 per month. The Schiller Consulting Agreement may be terminated by the Company upon 30 days’ notice, by mutual agreement, upon Mr. Schiller’s death and by either party upon the material breach of the Schiller Consulting Agreement or the Schiller Employment Agreement.

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Appointment of Interim CEO.

In light of Mr. Schiller’s departure, the Board has appointed Michael S. Reddin to serve as our President and Chief Executive Officer on an interim basis, effective February 2, 2017. We entered into an employment agreement with Michael S. Reddin (the “Interim CEO Employment Agreement”) in connection with his appointment by the Board as our CEO and President on an interim basis, effective as of February 2, 2017. The Interim CEO Employment Agreement has an initial term expiring one month after the date a successor CEO and President is appointed by the Board, unless terminated earlier by either party upon 30 days advance written notice (the “Employment Term”). That agreement provides for a monthly salary of $100,000, prorated for any partial month of service during the Employment Term. During the Employment Term, Mr. Reddin will continue to serve as a director and as Chairman of the Board. However, in light of his employee status, Mr. Reddin has resigned from the Board’s Nomination and Governance Committee.

During the Employment Term, (i) Mr. Reddin will continue to receive the annual restricted stock grants and annual cash retainer awarded to non-employee members of the Board including director compensation payable based on Mr. Reddin’s service as Chairman of the Board or with respect to any other positions held by Mr. Reddin as a director of the Company (including Chairman of the Board) and (ii) Mr. Reddin will continue to vest in his outstanding equity awards as if he remained a non-employee member of the Board during the Employment Term. However, Mr. Reddin will not be entitled to participate in any severance plan or otherwise receive any severance benefits or participate in the Company’s employee equity compensation program.

Departure of Bruce Busmire.

Mr. Busmire ceased to serve as our Chief Financial Officer on February 2, 2017. Mr. Busmire is not party to an employment agreement with us, nor does he participate in a severance plan. We have agreed to provide Mr. Busmire a severance payment in the amount of $750,000, less applicable taxes and withholdings, in consideration for the performance of the terms and conditions set forth in his Resignation Agreement and General Release, including, without limitation, a general release and non-disparagement provision. We have also agreed to reimburse Mr. Busmire for the monthly cost of maintaining health benefits for Mr. Busmire and his spouse and eligible dependents as of the date of his termination for a period of 18 months to the extent Mr. Busmire elects COBRA continuation coverage.

Departure of Antonio de Pinho.

Mr. Antonio de Pinho ceased serving as our Chief Operating Officer on February 2, 2017. Mr. de Pinho is not party to an employment agreement with us, nor does he participate in a severance plan. We have agreed to provide Mr. de Pinho a severance payment in the amount of $750,000, less applicable taxes and withholdings, in consideration for the performance of the terms and conditions set forth therein, including, without limitation, a general release and non-disparagement provision. We have also agreed to reimburse Mr. de Pinho for the monthly cost of maintaining health benefits for Mr. de Pinho and his spouse and eligible dependents as of the date of his termination for a period of 18 months to the extent Mr. de Pinho elects COBRA continuation coverage.

Appointment Chief Operating Officer.

On February 2, 2017, the Board appointed Scott M. Heck as our Chief Operating Officer. In connection with his appointment we entered into an employment agreement with Mr. Heck (the “COO Employment Agreement”) effective as of February 2, 2017. The COO Employment Agreement has a term of three years (the “Employment Period”) and provides for an annual salary of $450,000 (the “Base Salary”), with an annual target bonus of 100% of Mr. Heck’s Base Salary. During the Employment Period, Mr. Heck will be eligible to participate in any equity compensation arrangement or plan offered to senior executives.

Additionally, on February 2, 2017, and pursuant to the terms of the COO Employment Agreement, Mr. Heck received an equity grant under the 2016 LTIP for the 2017 calendar year with a grant date value equal to 200% of the Base Salary (the “2017 Equity Grant”). In order to implement the 2017 Equity Grant, Mr. Heck was granted (i) options to acquire 44,363 shares of the Company’s Common Stock, par value $0.01 per share (“Common Stock”), with an exercise price of $30.50 per share and a ten year term (the “Options”) and (ii) 14,754 stock-settled restricted stock units (the “RSUs”). The Options and the RSUs granted to

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Mr. Heck vest as follows: (i) 33% on February 2, 2018, (ii) 33% on February 2, 2019 and (iii) 34% on February 2, 2020, in each case provided that Mr. Heck remains continuously employed by us on the applicable vesting date. If a Change of Control (as defined in the 2016 LTIP) occurs while Mr. Heck is still employed by us, then any unvested RSUs or Options will immediately become vested and will be subject to the terms of the 2016 LTIP. Any Options that have not been exercised or forfeited on February 2, 2027 will expire at that time.

Should Mr. Heck be terminated by us for Cause or should Mr. Heck terminate his employment other than for Good Reason (as defined in the COO Employment Agreement), we will make no further payments under the COO Employment Agreement other than the following (collectively, the “Accrued Benefits”):

• the salary and business expenses to which he is entitled immediately prior to such termination;

• any bonus or other incentive award that (x) relates to a completed performance period and (y) has been earned but not yet paid on or prior to Mr. Heck’s termination date; and

• any other amounts or benefits required to be paid or provided by law or under any of our plans, programs, policies or practices.

Should Mr. Heck be terminated by us without Cause or should Mr. Heck resign for Good Reason, Mr. Heck will receive his Accrued Benefits, and subject to Mr. Heck’s continuing compliance with the nondisclosure, non-compete, non-solicitation and non-disparagement provisions in the COO Employment Agreement, Mr. Heck will be entitled to the following:

• A lump sum cash payment in an amount equal to (i) 200% of the Base Salary plus (ii) a bonus severance component calculated in the manner described below; and

• Reimbursement for the monthly cost of maintaining health benefits for Mr. Heck (and Mr. Heck’s spouse and eligible dependents) as of the date of termination of employment under our group health plan for purposes of the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”), excluding any short-term or long-term disability insurance benefits, for a period of 18 months following the date of the termination of employment, to the extent Mr. Heck elects COBRA.

The severance component relating to Mr. Heck’s bonus compensation is calculated in accordance with the table set forth below. However, for purposes of the calculation, each actual Bonus for a prior year included in the calculation will be capped at the Target Bonus for that prior year.

If the termination of employment occurs during:	Bonus Severance Component
The year ending December 31, 2017	100% of Target Bonus for year ending December 31, 2017
The year ending December 31, 2018	200% of actual Bonus paid for year ending December 31, 2017
Any calendar year after 2018	200% of average actual Bonuses paid for the most recent two completed years

During the term of Mr. Heck’s employment and for a period of twelve months thereafter, Mr. Heck cannot: (i) perform services for, or have over a five percent (5%) ownership interest in, or participate in, any competing business; or (ii) solicit, recruit or hire, or assist any person, or entity in the solicitation, recruitment or hiring of any person engaged by us as an employee, officer, director or consultant.

For purposes of the Heck Employment Agreement, “Cause” means (i) gross negligence or willful misconduct in the performance of, or abuse of alcohol or drugs rendering Mr. Heck unable to perform his material duties, provided that the conduct remains remedied for twenty days following receipt of written notice; (ii) conviction of, or plea of nolo contendere to, any crime involving moral turpitude or a felony; (iii) commission of an act of embezzlement, deceit or fraud intended to result in Mr. Heck’s personal and unauthorized enrichment at our expense; (iv) the material violation of the Heck Employment Agreement, our written policies, or any other agreement between Mr. Heck and us; (v) failure to follow a lawful directive of the CEO or the Board.

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For purposes of the Heck Employment Agreement, “Good Reason” means (i) the material diminution of Mr. Heck’s authority, duties or responsibilities; (ii) a material diminution of Mr. Heck’s base salary or target bonus; (iii) the requirement that Mr. Heck permanently relocate anywhere outside the greater Houston, Texas metropolitan area; or (iv) our material breach of the Heck Employment Agreement.

Part II: Elements of Compensation

Below is a summary of the elements of our Named Executive Officers’ compensation for the transition period from July 1, 2016 through December 31, 2016, each of which has historically been reviewed annually:

Element	Objective	Design Elements
Base salary	To provide a baseline level of cash compensation to recognize qualifications and industry experience	Reviewed annually with consideration given to an individual’s performance and experience level
Cash bonus	To motivate and reward executive officers’ contributions to achieve short-term performance goals	Balanced scorecard that rewards executives for the achievement of pre-established strategic, financial, and operational goals
Retirement benefits	401(k): To provide retirement benefits and encourage retention	401(k): All eligible employees receive a company matching contribution based on pretax contributions in an amount equal to 100% of the first 6% of eligible compensation contributed to the plan
	Profit sharing: To provide retirement benefits and encourage retention	Profit sharing: Annually pays an amount equal to up to 10% of employee’s base salary and cash bonus
Health and welfare benefits	To provide health and welfare benefits to executives	Health and welfare benefits including medical, dental, vision and disability coverage. The Company provides the same level of benefits to both executives and employees except that Mr. Schiller has no co-payment for eligible health benefits pursuant to his Employment Agreement
Severance	To mitigate uncertainty and motivate executives to focus on shareholder value irrespective of termination or in the event of a change in control	See Potential Payments upon Termination or a Change in Control — Payments upon Termination of Mr. Schiller.
Perquisites	Generally discouraged, but utilized in limited circumstances where a business reason exists for the benefit	Other than executive life insurance coverage and use of a company-leased automobile the Company does not generally provide perquisites

Part III: Factors for Determining Fiscal Year 2016 Compensation

As in past years, our executive compensation program for the transition period from July 1, 2016 through December 31, 2016 primarily consisted of the elements described above.

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We do not set targets for the mix of compensation among the various elements when determining compensation awards. The mix of value attributable to each of the elements of compensation is generally driven by our desire to emphasize variable and at risk compensation, such as cash bonus and long-term incentives, over fixed compensation. We believe this approach to compensation allocation supports our entrepreneurial culture and aligns our executives with shareholders.

Individual performance has a significant impact on determining each compensation component, other than for certain perquisites and benefits that are provided to all of our executive officers. Each individual Named Executive Officer’s annual performance is evaluated based on a review of his contributions to our business results both for the year and the long-term impact of the individual’s behavior and decisions. As a result of our yearly review for fiscal year 2016, the Predecessor Compensation Committee made the adjustments listed below for each element of compensation.

Base Salary

Our goal is to set base salaries for our Named Executive Officers at levels that are competitive in order to attract and retain top talent. The individual base salary levels are generally reviewed annually and are adjusted as appropriate based on an analysis of individual performance and experience, and our financial performance. This base salary review is performed in connection with the annual competitive compensation review.

In light of our Predecessor’s stock price and the market environment at the time that the Predecessor Compensation Committee was determining executive compensation for fiscal year 2016, the Predecessor Compensation Committee elected to freeze base salaries for fiscal year 2016, and no base salary increases were provided to our Named Executive Officers.

Cash Bonuses

No cash bonuses were awarded or paid during the transition period from July 1, 2016 through December 31, 2016. No decisions have been made by the Compensation Committee regarding cash bonuses for fiscal year 2017.

Long-term Incentives

As a result of the Plan, there are no assets remaining in EXXI Ltd, and, under Bermuda law, shareholders of EXXI Ltd will receive no payments. EXXI Ltd will be dissolved at the conclusion of the Bermuda Proceeding, and as such, the shareholders will no longer have any interest in EXXI Ltd as a matter of Bermuda law. Therefore, our Named Executive Officers will not receive any value for their restricted stock units (whether time based or performance based) described below to the extent those awards had vesting dates following our emergence from Chapter 11.

Our long-term incentives have been designed to provide performance-based awards to our executives and employees for their contribution to our stability, growth and creation of shareholder value over the long term. Our long-term incentives were previously provided under the Energy XXI Services, LLC 2006 Long-Term Incentive Plan (the “Predecessor LTIP”) last amended and approved by shareholders at the 2015 EXXI Ltd Annual General Meeting. The Predecessor LTIP provided our Predecessor the authority to offer stock options, stock appreciation rights, restricted shares and other stock or performance-based awards.

On the Emergence Date, we entered into the 2016 LTIP, which is a comprehensive equity-based award plan as part of the go-forward compensation for our officers, directors, employees and consultants (“Service Providers”). The total number of shares of our common stock reserved and available for delivery with respect to awards under the 2016 LTIP is 1,859,552 shares (or 5% of the total new equity). Our Board will determine the types of equity based awards (which may include stock option, stock appreciation rights, restricted stock, restricted stock units, bonus stock awards, performance awards, other stock based awards or cash awards) and the terms and conditions (including vesting and forfeiture restrictions) of such awards. Awards under the 2016 LTIP will be awarded to the Service Providers selected in the discretion of our Board; provided, however, that 3% of the 5% total new equity on a fully diluted basis reserved under the 2016 LTIP must be allocated by our Board no later than 120 days after the Emergence Date.

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Severance or Change in Control Benefits

Prior to our emergence from the Chapter 11 Cases, we provided the Named Executive Officers with certain severance and change in control payments through Mr. Schiller’s Employment Agreement and the Energy XXI Services, LLC Employee Severance Plan (“Severance Plan”). In connection with our emergence, the Severance Plan was terminated, and Mr. Schiller entered into a new employment agreement.

Other Benefits

While not the primary focus of our compensation plans, the Predecessor Compensation Committee determined that the perquisites and other benefits the Predecessor provided to its Named Executive Officers in the transition period from July 1, 2016 through December 31, 2016 were necessary in order to ensure each of its executives have a total compensation package that was competitive with market practices. Many of our Predecessor’s benefits plans, such as matching contributions to our 401(k) plan, are standard in the market place for qualified executive officers and, thus, both the Compensation Committee and Predecessor Compensation Committee believe such offerings are necessary to hire and retain qualified personnel. Likewise, we continue to provide additional benefits such as our profit sharing contributions, which are offered to all employees, additional life insurance coverage and use of Company-leased automobiles to remain competitive for qualified executive officer personnel and certain other executives.

Profit Sharing Arrangements

An additional component of our annual compensation program is our discretionary profit sharing program, which may annually pay an amount equal to up to 10% of an applicable employee’s base salary and cash bonus to the Energy XXI Services 401(k) Plan. The Compensation Committee has complete discretion, taking into account management’s recommendation and any other factors it may deem appropriate, to make the determination about the percentage of the respective Named Executive Officer’s compensation that will be contributed by us in any annual period. Such contributions are, to the extent they exceed certain 401 (k) levels, made to the Energy XXI Services LLC Restoration Plan, which is a nonqualified deferred compensation program.

No profit sharing amounts were paid to the Named Executive Officers during the transition period from July 1, 2016 to December 31, 2016.

The profit sharing amounts paid to the Named Executive Officers are reported in the Summary Compensation Table under the “All Other Compensation” column and the specific amounts are specifically set forth in the footnote to such column.

Part IV: Roles of Contributors to our Compensation Program

Oversight of the Compensation Program

The Compensation Committee is responsible for overseeing the compensation programs and policies for the Executive Officers. As part of that responsibility, the Compensation Committee reviews our compensation and benefits policies, evaluates the performance of our chief executive officer and approves the compensation levels for our Executive Officers. Additionally the Compensation Committee, along with our Board of Directors, reviews, equity-based compensation plans and other compensation arrangements for the Executive Officers.

Role of Compensation Committee in Compensation Decisions

Each director who is a member of the Compensation Committee qualifies as an “independent” director under the NASDAQ Listing Standards. The Compensation Committee makes compensation decisions for each Named Executive Officer. The Compensation Committee may also seek recommendations with respect to the compensation of our Named Executive Officers from independent consultants. The Compensation Committee may also receive input from management. However, the Compensation Committee will make all final decisions for our Named Executive Officers.

Role of Outside Consultants in Compensation Decisions

No compensation decisions were made during the transition period from July 1, 2016 to December 31, 2016, and no independent consultant was utilized.

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Part V: Material Tax and Accounting Considerations

In designing our compensation programs, we take into consideration the tax and accounting effect that each element will or may have on us, the Named Executive Officers and other employees as a group. We aim to keep the expense related to our compensation programs as a whole within certain affordability levels. The number of shares of common stock available under the 2016 LTIP and/or subject to equity awards may also be adjusted by the Compensation Committee to prevent dilution or enlargement of rights in the event of various changes in our capitalization.

We account for employee share-based awards in accordance with the provisions of FASB ASC Topic 718. All share-based payments to employees, including grants of restricted shares and options under the 2016 LTIPP, are measured at fair value on the date of grant and recognized in the statement of operations as compensation expense over their requisite service periods.

Section 162(m) of the Internal Revenue Code, as amended, generally disallows a tax deduction to public companies for certain compensation in excess of $1 million paid to our chief executive officer and our three other most highly compensated executive officers other than our principal financial officer. While we will continue to assess the impact of Section 162(m) on compensation arrangements during our upcoming fiscal year, we presently expect that the bonus payments and the awards of restricted shares, restricted stock units, stock options and performance units will not likely qualify for exclusion from the million dollar cap when paid. Maintaining tax deductibility will not be the sole consideration taken into account by the Compensation Committee in determining what compensation arrangements are in our and our shareholders’ best interests.

Compensation Committee Report

No portion of this report and the information contained in this report shall be deemed to be incorporated by reference into any filing under the Securities Act or under the Exchange Act through any general statement incorporating by reference in this Form 10-K in which this report appears in its entirety, except to the extent that the company specifically incorporates this report or a portion of this report by reference. Furthermore, this report and the information contained in this report shall not be deemed to be “soliciting material” or “filed” under such Acts.

The Compensation Committee of the Company is responsible for:

• reviewing, evaluating and approving the agreements, plans, policies and programs of the Company to compensate its officers and directors,

• reviewing and discussing with the Company’s management the “Compensation Discussion and Analysis” to be included in the Company’s Annual Reports on Form 10-K for the and to determine whether to recommend to our Board of Directors that the “Compensation Discussion and Analysis” be included in such reports, in accordance with the applicable rules and regulations,

• producing a report on executive compensation each year for publication in our Annual Reports on Form 10-K, in accordance with the applicable rules and regulations, and

• discharging our Board of Directors responsibilities relating to compensation of our officers and directors.

Among other things, we review general compensation issues and determine the compensation of all of our officers, including the Named Executive Officers. The Compensation Committee has the authority described in the Compensation Committee Charter, which has been approved by our Board of Directors. The Compensation Committee Charter provides that the Compensation Committee has all authority of our Board of Directors as required or advisable to fulfill the purposes of such committee, and permits such committee to form and delegate some or all of its authority to subcommittees when it deems appropriate. A copy of the Compensation Committee Charter is available on the Company’s website at www.energyxxi.com under and “Corporate Governance.”

The Compensation Committee currently consists of Messrs. Pully (who serves as its chair), Bahorich, Kollitides and Swent. Each of such members of the Compensation Committee meets the independence requirements established by our Board of Directors and as set forth in the NASDAQ Listing Standards.

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We have reviewed and discussed the Compensation Discussion and Analysis included herein, and we met and held discussions with the Company’s management with respect to the Compensation Discussion and Analysis. Based upon our review and discussions with management, we recommended to our Board of Directors that the Compensation Discussion and Analysis be included in the Company’s Transition Report on Form 10-K for the period ended December 31, 2016 for filing with the SEC.

Respectfully submitted by the Compensation Committee,
Steven Pully, Chairman
Michael S. Bahorich
George Kollitides
James W. Swent, III

Summary Compensation Table

The compensation disclosed in the summary compensation table for each named executive officer was for services provided for each fiscal year covered in all capacities to EXXI Ltd and its subsidiaries. EXXI Ltd provided compensation to our named executive officers under the terms of the employment agreement with Mr. Schiller, EXXI Ltd’s 2006 LTIP Plan and other compensation programs. All of the named executive officers who are currently employed by us, other than Mr. Schiller, are “at will” employees and do not have employment contracts with us.

As a result of the Plan, there are no assets remaining in EXXI Ltd, and, under Bermuda law, shareholders of EXXI Ltd will receive no payments. EXXI Ltd will be dissolved at the conclusion of the Bermuda Proceeding, and as such, the shareholders will no longer have any interest in EXXI Ltd as a matter of Bermuda law. As a result, all awards under the Predecessor LTIP, including performance-based awards and share-based compensation plans that remained unvested at the Emergence Date were cancelled and shareholders received no payments with respect to the shares of common stock of EXXI Ltd. Additionally, at the Emergence Date, all of EXXI Ltd’s existing share-based compensation plans, the 2008 Fair Market Value Purchase Plan and Employee Stock Purchase Plan were cancelled.

The following table presents information concerning compensation earned by, paid to or accrued for our named executive officers for the six month transition period from July 1, 2016 to December 31, 2016 and for EXXI Ltd’s fiscal years ended June 30, 2016 and June 30, 2015.

Name and Principal Position	Year/Period(1)		Salary(2)		Bonus(3)		Non-Equity Incentive Plan Compensation		Stock Awards		All Other Compensation(4)		Total
John D. Schiller, Jr.(7) Former President & Former Chief Executive Officer		12/31/2016	$	455,000	$	—	$	—	$	—	$	25,662	$	480,662
		2016		910,000		568,750		1,472,016		1,203,614		134,628		4,289,008
		2015		908,750		—		—		7,900,568		410,350		9,219,668
		2014		891,250		1,850,000		—		11,429,350		331,784		14,502,384
Bruce W. Busmire Former Chief Financial Officer		12/31/2016		260,000		—		—		—		9,000		269,000
		2016		520,000		234,000		700,960		573,150		54,125		2,082,235
		2015		366,667		80,000		—		1,907,500		19,400		2,373,567
Hugh Menown Interim Chief Financial Officer & Chief Accounting Officer		12/31/2016		212,500		100,000		—		—		10,364		322,864
		2016		425,000		159,375		412,488		542,752		66,653		1,606,268
		2015		422,083		505,000		—		2,219,797		120,550		3,267,430
		2014		385,833		460,000		—		2,988,420		111,233		3,945,486
Antonio de Pinho Former Chief Operating Officer		12/31/2016		260,000		—		—		—		600		260,600
		2016		520,000		234,000		700,960		573,150		46,125		2,074,235
		2015		483,125		115,000		—		4,216,223		131,125		4,945,473
		2014		372,917		485,000		—		2,873,250		114,241		3,845,408

(1) References to “12/31/2016” in this column are to the six month transition period from July 1, 2016 to December 31, 2016. References to “2016” in this column are to EXXI Ltd’s fiscal year ended June 30, 2016 (the “2016 fiscal year”) and references to “2015” in this column are to EXXI Ltd’s fiscal year ended June 30, 2015 (the “2015 fiscal year”)

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(2) In July 2015, EXXI Ltd’s Compensation Committee determined not to change the base salary rates for the named executive officers for the 2016 fiscal year and retained the base salary rates that were in effect for the 2015 fiscal year. In July 2014, the EXXI Ltd’s Compensation Committee approved an increase in the base salary rate for each named executive officer for fiscal year 2015. The slight discrepancy in the “Salary” column above between fiscal year 2015 and fiscal year 2016 is the result of each named executive officer receiving one month’s pay based on their fiscal year 2014 base rate for July 2014 before the raise was implemented in August 2014.

(3) Fiscal 2016 annual bonuses were paid in April 2016. Amounts paid in respect to EXXI Ltd’s profit sharing program under its 401(k) plan are not included in the “Bonus” column but are reported under the “All Other Compensation” column and discussed in footnote (6) below.

(4) For 2016, “All Other Compensation” amounts in the Summary Compensation Table consist of the following items:

Name	Period(a)		Insurance(b)		Health Club Allowance(c)		Automobile Lease(d)		Clubs(e)		Deferred Compensation Plan(f)		Profit Sharing(g)		401(k) Company Match(h)		Total
John D. Schiller, Jr.(7)		12/31/2016		—		600		12,142		12,880		—		—		—		25,622
Bruce W. Busmire		12/31/2016		—		600		8,400		—		—		—		—		9,000
Hugh Menown		12/31/2016		—		600		8,400		1,364		—		—		—		10,364
Antonio de Pinho		12/31/2016		—		600		—		—		—		—		—		600

(a) References to “12/31/2016” in this column are to the six month transition period from July 1, 2016 to December 31, 2016.

(b) Represents the value of life insurance premiums paid by EXXI Ltd’s on behalf of the named executive officer.

(c) Represents the amount paid by EXXI Ltd to subsidize a portion of health club dues of the respective named executive officer.

(d) Represents the amount paid by EXXI Ltd for its Company-leased automobiles provided for use by the respective named executive officer.

(e) Represents club dues paid by EXXI Ltd.

(f) Represents EXXI Ltd’s contributions made to our nonqualified deferred compensation plan on behalf of our named executive officers.

(g) Represents EXXI Ltd’s profit sharing contributions made on behalf of each named executive officer to its 401(k) plan. EXXI Ltd’s contributions on behalf of each named executive officer pursuant its profit sharing program that exceed certain legal limitations applicable to its 401(k) plan are made to EXXI Ltd’s nonqualified deferred compensation plan.

(h) Represents EXXI Ltd’s matching contributions made on behalf of each named executive officer to its 401(k) plan.

Grants of Plan-Based Awards in Transition Period

No grants of plan-based awards were made during the transition period from July 1, 2016 through December 31, 2016.

Outstanding Equity Awards at 2016 Fiscal Year-End

All outstanding equity awards were cancelled in connection with the Debtors’ emergence from the Chapter 11 Cases. As such, no equity awards were outstanding as of December 31, 2016, the last day of the transition period.

Option Exercises and Stock Vested in Fiscal Year 2016

No options were exercised and no awards vested during the transition period from July 1, 2016 through December 31, 2016. All options and stock awards were cancelled in connection with the Debtors’ emergence from the Chapter 11 Cases.

Nonqualified Deferred Compensation

Each of our Named Executive Officers is eligible to participate in the Energy XXI Services, LLC Restoration Plan (the “Restoration Plan”). The plan is an unfunded arrangement intended to be exempt from

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the participation, vesting, funding and fiduciary requirements set forth in Title I of the Employee Retirement Income Security Act of 1974, as amended, and to comply with Section 409A of the Code. Our obligations under the plan will be general unsecured obligations to pay deferred compensation in the future to eligible participants in accordance with the terms of the plan from our general assets. The Compensation Committee acts as the plan administrator.

The Restoration Plan provides for four different types of contributions: (1) employee deferral contributions, (2) employer matching contributions otherwise payable to our tax qualified retirement plan but for non-discrimination rules limiting the amount of employee compensation that can be considered in calculating matching contributions under that plan, (3) profit sharing contributions otherwise payable to our tax qualified retirement plan but for non-discrimination rules limiting the amount of employee compensation that can be considered in calculating profit sharing contributions under that plan, and (4) discretionary employer contributions. Employee deferral contributions are always 100% vested and nonforfeitable. Historically, employer contributions have also been 100% vested, however, beginning January 1, 2013, an employee must be employed on the last day of any calendar year in order to receive a discretionary employer contribution for that calendar year. Compensation for purposes of the plan includes the base compensation and bonuses.

A participant’s Restoration Plan account balance generally will be paid in a single lump sum distribution on the date that is six months following the participant’s separation from service or, if earlier, upon the participant’s death. In addition, to the extent an employee makes employee deferral contributions to the Restoration Plan, the employee may also elect to receive a distribution of such amounts upon the earlier to occur of a fixed date (which is at least two years after the plan year of such deferrals) or the date that is six months following the participant’s separation from service (or, if earlier, upon the participant’s death). All amounts under the Restoration Plan are invested in the same investment elections provided under our tax-qualified retirement plan and, consequently, earnings do not constitute above market earnings or interest for purposes of SEC disclosure rules.

Nonqualified Deferred Compensation Table for Transition Period

Name(1)	Company Contributions in 2016 ($)(2)		Aggregate Earnings in 2016 ($)			Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at end of 2016 ($)(3)
John D. Schiller, Jr.	$	—	$	(5,455	)	$	—	$	50,451
Bruce Busmire		—		8			—		20,108
Hugh Menown		—		(152	)		—		118,040
Antonio de Pinho		—		58			—		157,927

(1) None of the Named Executive Officers made employee deferral contributions to the Restoration Plan during the transition period from July 1, 2016 through December 31, 2016.

(2) All amounts reflected in this column have also been reported in the Summary Compensation Table under the heading of “All Other Compensation” for the transition period.

(3) We have reported the following amounts as contributed to the Restoration Plan on behalf of the Named Executive Officers in prior fiscal years: (a) Mr. Schiller — $298,950 (2015 fiscal year), $231,900 (2014 fiscal year), $377,333 (2013 fiscal year), $358,971 (2012 fiscal year), $350,615 (2011 fiscal year), $148,533 (2010 fiscal year), $102,708 (2009 fiscal year), $307,010 (2008 fiscal year) and $70,000 (2007 fiscal year); (b) Mr. Menown — $72,550 (2015 fiscal year), $59,433 (2014 fiscal year), $76,500 (2012 fiscal year) and $39,590 (2011 fiscal year); and (c) Mr. de Pinho — $76, 275 (2015 fiscal year) and $59,367 (2014 fiscal year).

Potential Payments upon Termination or a Change in Control

As discussed above in the Compensation Discussion and Analysis, we believe that it is important to provide our Named Executive Officers with certain severance and change in control payments or benefits in order to establish a stable work environment for the individuals responsible for our day to day management.

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In order to assist us in this goal, Mr. Schiller’s prior employment agreement was terminated, and we entered into a new Employment Agreement with Mr. Schiller effective as of December 30, 2016 (the “Employment Agreement”).

Other than payments made due to an actual termination of employment, payments and benefits described in this discussion assumes for illustrative purposes that termination events occurred on December 30, 2016 and are made pursuant to the terms of the Employment Agreement.

Payments upon Termination of Mr. Schiller

On the Emergence Date, we entered into the Employment Agreement with John D. Schiller, Jr. as our President and Chief Executive Officer. The Employment Agreement supersedes the employment agreement Mr. Schiller had in place with EXXI Ltd prior to the Emergence Date. The Employment Agreement has an initial term expiring on December 30, 2019 and provides for an annual base salary of $910,000 (“Base Compensation”) with an annual target bonus of 125% of Mr. Schiller’s Base Compensation (“Target Bonus”).

Should Mr. Schiller be terminated by us for Cause (as defined in the Employment Agreement) or should Mr. Schiller terminate his employment other than for Good Reason (as defined in the Employment Agreement), we will make no further payments under the Employment Agreement other than the salary and business expenses to which he is entitled immediately prior to such termination (the “Accrued Benefits”).

Should Mr. Schiller be terminated by us for a reason other than for Cause (other than due to his death or Disability (as defined in the Employment Agreement)) or should Mr. Schiller resign for Good Reason, Mr. Schiller will receive the Accrued Benefits, and subject to Mr. Schiller executing and not revoking a mutual release of claims, Mr. Schiller will be entitled to the following:

• on or prior to the first anniversary of the Emergence Date, (i) a lump sum of $2 million and (ii) reimbursement for the monthly cost of maintaining health benefits for Mr. Schiller and his spouse and eligible dependents as of the date of termination of employment for a period of 18 months to the extent Mr. Schiller elects continuation coverage pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”).

• after the first anniversary of the Emergence Date, (i) three times his Base Compensation and Target Bonus and (ii) reimbursement for the monthly cost of maintaining health benefits for Mr. Schiller and his spouse and eligible dependents as of the date of termination of employment for a period of 18 months to the extent Mr. Schiller elects COBRA continuation coverage.

In the event of Mr. Schiller’s death or his termination by us on account of his Disability during the term of the Employment Agreement, we will be obligated to continue for twelve months after his death or such termination due to Disability to pay the Base Compensation payments to Mr. Schiller or his beneficiary, or if none, his estate, as applicable.

During the term of Mr. Schiller’s employment and for a period of twelve months thereafter, Mr. Schiller cannot: (i) perform services for, or have over a five percent (5%) ownership interest in, or participate in competing business; or (ii) solicit, recruit or hire, or assist any person, or entity in the solicitation, recruitment or hiring of any person engaged by the New Parent as an employee, officer, director or consultant.

Payments upon Termination of Messrs. Busmire, Menown or de Pinho

In connection with our emergence from the Chapter 11 Cases, the Severance Plan and performance unit awards were terminated. Additionally, none of Messrs. Busmire, Menown and de Pinho are party to employment agreements with us. As such, none of Messrs. Busmire, Menown and de Pinho would be entitled to receive severance payments upon a change of control or any kind of termination of employment with us, other than payments required by applicable law.

Quantification of Potential Payments upon Termination or a Change in Control

For purposes of the table below, we made reasonable assumptions, such as all legitimate reimbursable business expenses and all earned salary payments are current on the date of the potential termination event. We assumed each event has occurred on December 30, 2016, on which day, following our emergence from

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the Chapter 11 Cases, all outstanding equity awards had been terminated. Actual amounts may not be determined with complete accuracy until such time as an actual termination or change of control occurs, but the values below are our best estimate as to the potential payments each Named Executive Officer would receive as of December 30, 2016.

Named Executive Officer	Termination by Executive for Good Reason, Termination by Company without Cause(1)		Disability		Death
John D. Schiller, Jr.
Salary	$	2,000,000	$	910,000	$	910,000
Bonus	$	—	$	—	$	—
Accelerated Equity	$	—	$	—	$	—
Continued Medical	$	46,722	$	—	$	—
Tax Gross-up	$	—	$	—	$	—

(1) In connection with Mr. Schiller’s resignation, described above, he is entitled to receive severance benefits as if he were terminated without Cause pursuant to his employment agreement with us. Absent our entry into a severance agreement with Mr. Busmire, he would not have been eligible for any severance upon his resignation. For more information regarding Mr. Schiller’s resignation, please read Part I —  “Compensation Changes Occurring After December 30, 2016.”

The Employment Agreement

The payments and benefits shown in this section with respect to Mr. Schiller reflect our obligations under his Employment Agreement as in effect as of December 30, 2016. Our “Severance” obligations are to make a lump sum payment on the date of termination, unless the executive is a “specified employee” pursuant to Section 409A of the Code and such Code section requires us to delay payments for a period of six months in order to comply with that Code section.

The Employment Agreement also contains certain restrictive covenants. In addition to customary confidentiality provisions, Mr. Schiller will be subject to one year non-compete and non-solicitation restrictions following a termination of his employment.

The following table summarizes certain definitions applicable to the Employment Agreement:

Term	Summary Definition
Cause	Executive’s (1) embezzlement, fraud, gross negligence or willful misconduct in the performance of his duties; (2) commission of a felony; or (3) material breach of the Employment Agreement or any other agreement with us; (4) failure to follow any lawful directive of the Board or other refusal to perform his duties, provided that we must provide Mr. Schiller with a reasonable opportunity to cure the failure or conduct. Termination for Cause can occur only after Mr. Schiller is provided an opportunity to be heard in person by the Compensation Committee of the Board and the Compensation Committee must approve the termination for Cause by a two-thirds vote.
Disability	Absence of executive from full-time performance for 180 business days during a 12 month period due to incapacity due to accident, physical or mental illness, or other circumstance in his physician’s opinion which renders him mentally or physically incapable of performing full-time duties.

187

Term	Summary Definition
Good Reason	The occurrence of any of the following, without the executive’s written consent and following at least 90 days’ notice and opportunity to cure of not less than 30 days: (a) change of executive’s title or the assignment of duties that materially adversely alters the status of his office, title, or responsibilities; (b) any material reduction in base compensation or target bonus opportunity; (c) the requirement to permanently relocate anywhere outside the greater Houston, Texas metropolitan area, except for required travel on our business; (d) our material breach of the Employment Agreement.

Events Occurring After December 30, 2016

As described in more detail above in Part I — “Compensation Changes Occurring After December 30, 2016,” on February 2, 2017 (the “Resignation Date”), Mr. Schiller, Mr. Busmire and Mr. de Pinho resigned their positions with us. In connection with their resignations, Mr. Schiller was entitled to severance benefits under the Schiller Employment Agreement and for Mr. Busmire and Mr. de Pinho, we agreed to provide a severance payment and also agreed to reimburse the monthly cost of maintaining health benefits.

Resignation Agreements.

Upon his resignation, Mr. Schiller became entitled to receive severance benefits as if he were terminated without Cause pursuant to his employment agreement with us. For more information and quantification of the payments and benefits due to Mr. Schiller in connection with his resignation, please read Part III, Item 11. “Executive Compensation — Quantification of Potential Payments upon Termination or a Change in Control.”

In connection with Mr. Busmire’s and Mr. de Pinho’s resignations, we entered into a Resignation Agreement and General Release (the “Resignation Agreement”) with them effective as of the Resignation Date. Pursuant to the terms of the Resignation Agreements, Mr. Busmire and Mr. de Pinho will receive (i) a lump sum severance payment in the amount of $750,000, less applicable taxes and withholdings and (ii) reimbursement for up to 18 months of the monthly premium cost incurred to maintain health coverage for himself, his spouse and his eligible dependents, a cost of $46,722, assuming such reimbursement will continue for the full 18 month period. The Resignation Agreement also acts as a full release of all of Mr. Busmire’s and Mr. de Pinho’s potential claims against us.

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

The following table sets forth the number and percentage of outstanding shares of our common stock that, according to the information available to us, were owned by (1) each of our directors, (2) each of our executive officers who are our “Named Executive Officers” for whom we provide compensation information in this Amendment, (3) each person known by us to be the beneficial owner of more than 5% of our outstanding common stock and (4) all of our directors and executive officers as a group as of February 20, 2017.

188

For purposes of the table below, we deem shares of common stock subject to options that are currently exercisable or exercisable within 60 days of February 20, 2017 to be outstanding and to be beneficially owned by the person holding the options for the purpose of computing the percentage ownership of that person, but we do not treat them as outstanding for the purpose of computing the percentage ownership of any other person. Except as otherwise noted, the persons or entities in this table have sole voting and investing power with respect to all of the shares of common stock beneficially owned by them, subject to community property laws, where applicable.

Name and Address of Beneficial Owner(1)	Amount and Nature of Beneficial Ownership(2)		Percent of Class
Franklin Resources, Inc.(3)		9,272,284		27.7	%
Oaktree Capital Management, L.P.(4)		3,374,976		10.1	%
Mudrick Capital Management, L.P.(5)		3,090,047		9.3	%
DW Partners, L.P.(6)		3,260,186		9.8	%
Tyrus Capital S.A.M.(7)		2,044,345		6.1	%
Michael S. Bahorich		—		—
George Kollitides		—		—
Steven Pully		—		—
Michael S. Reddin		—		—
James “Jay” W. Swent III		—		—
Charles W. Wampler		—		—
Scott M. Heck		—		—
Hugh A. Menown		—		—
All directors and officers as a group as of February 20, 2017		—		—

(1) Except as expressly stated otherwise, the address for the beneficial owners listed below is: Energy XXI Gulf Coast, Inc., 1021 Main Street, Suite 2626, Houston, Texas 77002.

(2) Beneficial ownership is determined in accordance with SEC rules and includes voting and investment power with respect to the shares of our common stock. Unless otherwise indicated, the persons named in the table have sole voting and dispositive power with respect to all shares beneficially owned. All calculations of percentage ownership herein are based on a total of 33,299,296 shares of common stock, outstanding, consisting of (i) 33,211,594 shares of Common Stock outstanding as of January 6, 2017, and (ii) 87,702 Warrants to purchase common stock held, entitling them to purchase an aggregate of 87,702 shares of common stock at an exercise price of $43.66 per share, subject to expiration on December 30, 2021. In accordance with Rule 13d-3(d)(1), the Warrants are treated as exercised for the purpose of computing the deemed beneficial ownership percentage.

(3) The principal address of Franklin Resources, Inc. is One Franklin Parkway, San Mateo, CA 94403-1906. In accordance with Rule 13d-3(d)(1), the amount of securities beneficially owned includes 222,356 Warrants held by Franklin Resources, Inc. or its affiliates.

(4) The principal address of Oaktree Capital Management, L.P. is 333 S. Grand Avenue, 28^th Floor, Los Angeles, CA 90071. In accordance with Rule 13d-3(d)(1), the amount of securities beneficially owned includes 87,702 Warrants held by Oaktree Capital Management, L.P or its affiliates.

(5) The principal address of Mudrick Capital Management, L.P. is 527 Madison Avenue, 6^th Floor, New York, NY 10022.

(6) The principal address of DW Partners, L.P. is 590 Madison Avenue, 13^th Floor, New York, NY 10022. In accordance with Rule 13d-3(d)(1), the amount of securities beneficially owned includes 59,543 Warrants held by DW Partners, L.P. or its affiliates.

(7) The principal address of Tyrus Capital S.A.M. is 4 Avenue Roqueville, Monaco, MC 98000. In accordance with Rule 13d-3(d)(1), the amount of securities beneficially owned includes 59,543 Warrants held by Tyrus Capital S.A.M. or its affiliates.

189

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

Transactions with Related Parties

On the Emergence Date, the Company entered into a Registration Rights Agreement with parties the Holders representing 10% or more of the Common Stock outstanding on that date or who acquire 10% or more of the Common Stock outstanding within six months of the Emergence Date. The Registration Rights Agreement provides resale registration rights for the Holders’ Registerable Securities (as defined in the Registration Rights Agreement). On or before the date that is 60 days after, the Emergence Date, the Company will file, and will thereafter use its commercially reasonable efforts to cause to be declared effective as promptly as practicable, a registration statement on Form S-3 (or other appropriate form) for the offer and resale of the Common Stock held by the Holders. On the Emergence Date, the Company also entered into the Warrant Agreement with Continental Stock Transfer & Trust Company, as Warrant Agent. On the Emergence Date, pursuant to the terms of the Plan, the Company issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims.

On the Emergence Date, pursuant to the Registration Rights Agreement and the Warrants Agreement, the Company issued (i) 27,897,739 shares of common stock, pro rata, to holders of the claims arising from the Second Lien Notes, (ii) 3,985,391 shares of common stock, pro rata, to holders of the claims arising from the EGC Unsecured Notes (the “EGC Unsecured Notes Claims”), (iii) 1,328,464 shares of common stock, pro rata, to holders of the claims arising from the EPL 8.25% Senior Notes (the “EPL Unsecured Notes Claims”), (iv) 1,271,933 warrants, pro rata, to holders of the EGC Unsecured Notes Claims; and (v) 847,956 warrants, pro rata, to holders of the EPL Unsecured Notes Claims.

Policies and Procedures Dealing with the Review, Approval and Ratification of Related Party Transactions

As part of the Code of Business Conduct and Ethics, the Board has adopted procedures related to the identification of conflicts of interests, including related party transactions. In accordance with the revised Code of Business Conduct and Ethics, all Company employees and directors must avoid any activity or personal interest that creates or appears to create a conflict between personal interests and the interests of the Company. To remove any such doubts or suspicion, Company employees must disclose any actual or potential conflicts of interests associated with the Company’s business, including any related party transactions, to the Chief Compliance Officer to assess the nature and extent of any concern and how it can be resolved. However, the Company’s directors, Chief Executive Officer, Chief Financial Officer, Chief Operating Officer and Executive Vice Presidents and other employees performing similar functions must disclose any such issues, including any related party transactions, to the Chairman of the Audit Committee. The related party transactions discussed above were approved in accordance with these procedures.

Director Independence

For a discussion of director independence, see Item 10, “Directors, Executive Officers and Corporate Governance.”

Item 14. Principal Accountant Fees and Services

BDO USA, LLP served as our independent registered public accounting firm for the transition period ended December 31, 2016 and the fiscal years ended June 30, 2016 and 2015.

190

Fees Paid to BDO USA, LLP

The following table sets forth the aggregate fees for professional services rendered by BDO USA, LLP for the transition period ended December 31, 2016 and the fiscal years ended June 30, 2016 and 2015 on behalf of our Company and our subsidiaries:

	Transition Period Ended December 31, 2016		Year Ended June 30, 2016		Year Ended June 30, 2015
Audit Fees(1)	$	1,320,000	$	1,793,853	$	2,924,866
Audit Related Fees(2)		—		25,000		28,000
Tax Fees(3)		—		—		—
All Other Fees(4)		—		—		—
Total Fees	$	1,320,000	$	1,818,853	$	2,952,866

(1) For the transition period ended December 31, 2016, audit fees are fees paid to BDO USA, LLP for professional services related to the audit and quarterly reviews of Reorganized EGC and its Predecessor, and for services that are normally provided by the accountant in connection with regulatory filings. Audit fees are fees paid to BDO USA, LLP for professional services in prior years related to the audit and quarterly reviews of our financial statements, including those of our subsidiaries, EPL Oil and Gas Inc. and Energy XXI Gulf Coast, Inc., and internal control over financial reporting and for services that are normally provided by the accountant in connection with regulatory filings. Audit fees include $28,016 related to services provided in connection with the review of registration statements, providing comfort letters and consents.

(2) Consists of fees for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “Audit Fees.” These services include, but are not limited to, special audits of employee benefit plans.

(3) No fees were paid to BDO USA, LLP for tax services.

(4) No other fees were paid to BDO USA, LLP.

Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accounting Firms

The Audit Committee pre-approves all audit and permissible non-audit services provided by BDO USA, LLP. These services may include audit services, audit-related services, tax services and other services. The Audit Committee may also pre-approve particular services on a case-by-case basis and may delegate pre-approval authority to one or more Audit Committee members. If so delegated, the Audit Committee member must report any pre-approval decision by him to the Audit Committee at its first meeting after the pre-approval was obtained.

191

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		88
Report of Independent Registered Public Accounting Firm		89
Report of Independent Registered Public Accounting Firm		90
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2016 (Successor) and June 30, 2016 and 2015 (Predecessor)		91
Consolidated Statements of Operations on December 31, 2016 (Successor) and for the Six Months Ended December 31, 2016 and Years Ended June 30, 2016, 2015 and 2014 (Predecessor)		93
Consolidated Statements of Stockholders’ Equity (Deficit) on December 31, 2016 (Successor) and for the Six Month Transition Period Ended December 31, 2016 and Years Ended June 30, 2016, 2015 and 2014 (Predecessor)		94
Consolidated Statements of Cash Flows on December 31, 2016 (Successor) and for the Six Month Transition Period Ended December 31, 2016 and Years Ended June 30, 2016, 2015 and 2014 (Predecessor)		95
Notes to Consolidated Financial Statements		97

(2) Financial Statement Schedules

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

(3) Exhibits

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

Item 16. Form 10-K Summary

None.

192

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 22^nd day of February 2017.

ENERGY XXI GULF COAST, INC.

By: /s/ MICHAEL S. REDDIN

Michael S. Reddin
Interim 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/ MICHAEL S. REDDIN Michael S. Reddin	Interim Chief Executive Officer (Principal Executive Officer)	February 22, 2017
/s/ HUGH MENOWN Hugh Menown	Interim Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	February 22, 2017
/s/ MICHAEL S. BAHORICH Michael S. Bahorich	Director	February 22, 2017
/s/ GEORGE KOLLITIDES George Kollitides	Director	February 22, 2017
/s/ STEVEN PULLY Steven Pully	Director	February 22, 2017
/s/ JAMES “JAY” W. SWENT III James “Jay” W. Swent III	Director	February 22, 2017
/s/ CHARLES W. WAMPLER Charles W. Wampler	Director	February 22, 2017

193

EXHIBIT INDEX

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
2.1	Purchase and Sale Agreement, dated June 22, 2015, by and between Grand Isle Corridor, LP and Energy XXI USA, Inc.	2.1 to Energy XXI Ltd’s Form 8-K filed on June 23, 2015	001-33628
2.2	Guaranty, dated June 22, 2015, by Energy XXI Ltd in favor of Grand Isle Corridor, LP	2.2 to Energy XXI Ltd’s Form 8-K filed on June 23, 2015	001-33628
2.3	Guaranty, dated June 22, 2015, by CorEnergy Infrastructure Trust, Inc. in favor of Energy XXI USA, Inc.	2.3 to Energy XXI Ltd’s Form 8-K filed on June 23, 2015	001-33628
2.4	Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization, dated December 13, 2016.	2.1 to the Company’s Current Report on Form 8-K filed on December 15, 2016	333-145639
3.1	Second Amended and Restated Certificate of Incorporation of Energy XXI Gulf Coast, Inc.	3.1 to the Company’s Form 8-K filed on January 6, 2017.	333-145639
3.2	Second Amended and Restated Bylaws of Energy XXI Gulf Coast, Inc.	3.2 to the Company’s Form 8-K filed on January 6, 2017	333-145639
3.3	Third Amended and Restated Bylaws of Energy XXI Gulf Coast, Inc.	3.1 to the Company’s Form 8-K filed on February 7, 2017	333-145639
10.1†	Executive Employment Agreement, dated as of December 30, 2016, by and between Energy XXI Gulf Coast, Inc. and John D. Schiller, Jr.	10.6 to the Company’s Form 8-K filed on December 30, 2016	333-145639
10.2†	Form of Indemnification Agreement between Energy XXI Gulf Coast, Inc. and Indemnitees	10.7 to the Company’s Form 8-K filed on December 30, 2016	333-145639
10.3†	Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan	10.8 to the Company’s Form 8-K filed on December 30, 2016	333-145639
10.4†	Energy XXI Gulf Coast, Inc. Non-Employee Director Compensation Policy	10.9 to the Company’s Form 8-K filed on December 30, 2016	333-145639
10.5†	Form of Restricted Stock Unit Award Agreement (for Directors)	4.4 to the Company’s Registration Statement on Form S-8 filed on January 17, 2017	333-145639
10.6†	Form of Notice of Grant of Restricted Stock Unit (Initial Director Award)	4.5 to the Company’s Registration Statement on Form S-8 filed on January 17, 2017	333-145639
10.7†	Form of Notice of Grant of Restricted Stock Unit (Annual Director Award)	4.6 to the Company’s Registration Statement on Form S-8 filed on January 17, 2017	333-145639
10.8†	Form of Restricted Stock Unit Initial Grant Settlement Election Form	4.7 to the Company’s Registration Statement on Form S-8 filed on January 17, 2017	333-145639
10.9†	Form of Restricted Stock Unit Annual Grant Settlement Election Form	4.8 to the Company’s Registration Statement on Form S-8 filed on January 17, 2017	333-145639

194

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.10†	Interim Chief Strategic Officer Agreement, dated as of February 23, 2015, between Energy XXI Services, LLC and James LaChance.	10.1 to Energy XXI Ltd’s Form 8-K filed on February 25, 2015	001-33628
10.11†	Waiver and Release of Claims Agreement, dated February 2, 2017, executed by John D. Schiller, Jr.	10.1 to the Company’s Form 8-K filed on February 7, 2017	333-145639
10.12†	Consulting Agreement, dated February 2, 2017, by and between Energy XXI Gulf Coast, Inc. and John D. Schiller, Jr.	10.2 to the Company’s Form 8-K filed on February 7, 2017	333-145639
10.13†	Employment Agreement, dated February 2, 2017, by and between Energy XXI Gulf Coast, Inc. and Michael S. Reddin	10.3 to the Company’s Form 8-K filed on February 7, 2017	333-145639
10.14†	Employment Agreement, dated February 2, 2017, by and between Energy XXI Gulf Coast, Inc. and Scott M. Heck	10.4 to the Company’s Form 8-K filed on February 7, 2017	333-145639
10.15†	Form of Restricted Stock Unit Agreement and form of related Notice of Grant	10.5 to the Company’s Form 8-K filed on February 7, 2017	333-145639
10.16†	Form of Option Agreement and form of related Notice of Grant	10.6 to the Company’s Form 8-K filed on February 7, 2017	333-145639
10.17†	Resignation Agreement and General Release, effective as of February 2, 2017, executed by Bruce Busmire and Energy XXI Gulf Coast, Inc	10.7 to the Company’s Form 8-K filed on February 7, 2017	333-145639
10.18†	Resignation Agreement and General Release, effective as of February 2, 2017, executed by Antonio de Pinho and Energy XXI Gulf Coast, Inc.	10.8 to the Company’s Form 8-K filed on February 7, 2017	333-145639
10.19	Transportation Agreement, dated as of March 11, 2015, between Energy XXI Gulf Coast, Inc. and Energy XXI USA, Inc.	10.13 to Energy XXI Ltd’s Form 10-Q filed on May 8, 2015	001-33628
10.20	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 Energy XXI Ltd’s Form 10-Q filed on May 8, 2015	001-33628
10.21	Lease, dated June 30, 2015, by and between Grand Isle Corridor, LP and Energy XXI GIGS Services, LLC	10.1 to Energy XXI Ltd’s Form 8-K filed on July 1, 2015	001-33628
10.22	Waiver to Lease by and between Grand Isle Corridor, LP and Energy XXI GIGS Services, LLC, dated April 13, 2016	10.2 to Energy XXI Ltd’s Form 8-K filed on April 14, 2016	001-33628

195

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.23	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 11.0% senior secured second lien notes, dated April 11, 2016	10.1 to Energy XXI Ltd’s Form 8-K filed on April 14, 2016	001-33628
10.24	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 11.0% senior secured second lien notes, dated May 16, 2016	10.1 to Energy XXI Ltd’s Form 8-K filed on May 20, 2016	001-33628
10.25	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 11.0% senior secured second lien notes, dated June 28, 2016	10.1 to Energy XXI Ltd’s Form 8-K filed on July 5, 2016	001-33628
10.26	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 11.0% senior secured second lien notes, dated July 28, 2016	10.1 to Energy XXI Ltd’s Form 8-K filed on August 1, 2016	001-33628
10.27	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 11.0% senior secured second lien notes, dated August 19, 2016	10.1 to Energy XXI Ltd’s Form 8-K filed on August 23, 2016	001-33628

196

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.28	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 11.0% senior secured second lien notes, dated September 13, 2016	10.1 to Energy XXI Ltd’s Form 8-K filed on September 13, 2016	001-33628
10.29	Plan Support Agreement by and among the Debtors, the Second Lien Plan Support Parties, the Creditors’ Committee, the EGC Plan Support Parties and the EPL Plan Support Parties, dated November 14, 2016.	10.5 to Energy XXI Ltd’s Form 10-Q filed on November 14, 2016	001-33628
10.30	Registration Rights Agreement, dated as of December 30, 2016, by and among Energy XXI Gulf Coast, Inc. and the stockholders party thereto	10.1 to the Company’s Form 8-K filed on January 6, 2017	333-145639
10.31	First Lien Exit Credit Agreement, dated as of December 30, 2016, by and among, Energy XXI Gulf Coast, Inc., the lenders party thereto, the guarantors party thereto and Wells Fargo Bank, N.A., as Administrative Agent	10.2 to the Company’s Form 8-K filed on January 6, 2017	333-145639
10.32	Guaranty, dated as of December 30, 2016, by the guarantors party thereto in favor of Wells Fargo Bank, N.A., as Administrative Agent, and the Secured Parties	10.3 to the Company’s Form 8-K filed on January 6, 2017	333-145639
10.33	First Lien Pledge and Security Agreement and Irrevocable Proxy, effective as of December 30, 2016, by Energy XXI Gulf Coast, Inc. and each of the Grantors party thereto in favor of Wells Fargo Bank, N.A., as Administrative Agent, and the Secured Parties	10.4 to the Company’s Form 8-K filed on January 6, 2017	333-145639
10.34	Warrant Agreement, dated as of December 30, 2016, by and between Energy XXI Gulf Coast, Inc. and Continental Stock Transfer & Trust Company, as Warrant Agent.	10.5 to the Company’s Form 8-K filed on January 6, 2017	333-145639
10.35	Assignment and Assumption Agreement, dated December 30, 2016, by and among Energy XXI USA, Inc., Energy XXI Gulf Coast, Inc. and Grand Isle Corridor, L.P.	Filed herewith

197

Exhibit Number	Exhibit Description	Originally Filed as Exhibit	File Number
10.36	Assignment and Assumption of Guaranty and Release, dated December 30, 2016, by and among Energy XXI Ltd, Inc., Energy XXI Gulf Coast, Inc. and Grand Isle Corridor, L.P.	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
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
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

198