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



 

FORM 10-Q



 

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

For the quarterly period ended December 31, 2015

OR

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

For the transition period from            to           

Commission File Number: 001-33628



 

ENERGY XXI LTD

(Exact name of registrant as specified in its charter)



 

 
Bermuda   98-0499286
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification Number)

 
Canon’s Court, 22 Victoria Street, PO Box HM
1179, Hamilton HM EX, Bermuda
  N/A
(Address of principal executive offices)   (Zip Code)

(441) 295-2244

(Registrant’s telephone number, including area code)



 

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 þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 þ No o

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. (Check one):

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

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

As of January 29, 2016, there were 95,459,002 shares outstanding of the registrant’s common stock, par value $0.005 per share.

 

 


 
 

TABLE OF CONTENTS

ENERGY XXI LTD
 
TABLE OF CONTENTS

 
  Page
GLOSSARY OF TERMS     1  
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS     3  
PART I — FINANCIAL INFORMATION
        

ITEM 1.

Unaudited Consolidated Financial Statements

    5  

ITEM 2.

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

    46  

ITEM 3.

Quantitative and Qualitative Disclosures About Market Risk

    65  

ITEM 4.

Controls and Procedures

    68  
PART II — OTHER INFORMATION
        

ITEM 1.

Legal Proceedings

    69  

ITEM 1A.

Risk Factors

    69  

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

    74  

ITEM 3.

Defaults upon Senior Securities

    74  

ITEM 4.

Mine Safety Disclosures

    74  

ITEM 5.

Other Information

    74  

ITEM 6.

Exhibits

    74  
SIGNATURES     75  
EXHIBIT INDEX     76  

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GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this Quarterly Report on Form 10-Q for the quarter ended December 31, 2015 (“Quarterly Report”):

     
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
MBbls   One thousand Bbls          

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

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

Development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploitation is drilling wells in areas proven to be productive.

Exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well or a service well.

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. For a complete definition of a field, refer to Rule 4-10(a) (8) of Regulation S-X as promulgated by the Securities and Exchange Commission (“SEC”).

Formation is a stratum of rock that is recognizable from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.

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

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

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

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

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

Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the fractional working interest owned in the properties.

Oil includes crude oil, condensate and natural gas liquids.

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

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

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

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

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

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

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

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For a complete definition of proved undeveloped oil and gas reserves, refer to Rule 4-10(a) (4) of Regulation S-X as promulgated by the SEC.

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

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

Reservoir refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Seismic is an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formations. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional pictures.

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

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

Zone is a stratigraphic interval containing one or more reservoirs.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report 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:

our business strategy;
further or sustained declines in the prices we receive for our oil and 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, cash flows and expenses;
the potential need to sell certain assets, restructure our debt, raise additional capital or seek bankruptcy protection;
our future levels of indebtedness, liquidity, compliance with financial covenants and our ability to continue as a going concern;
the size of our borrowing base under our second amended and restated first lien credit agreement, any reduction in which would result in a deficiency that would have to be repaid within 45 days;
our ability to continue to borrow under our second amended and restated first lien credit agreement;
our inability to obtain additional financing necessary to fund our operations, capital expenditures, and to meet our other obligations;
our ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by the Bureau of Ocean Energy Management (the “BOEM”);
economic slowdowns that can adversely affect consumption of oil and gas by businesses and consumers;
uncertainties in estimating our oil and gas reserves and net present values of those reserves;
the need to take ceiling test impairments due to lower commodity prices;
hedging activities exposing us to pricing and counterparty risks;
replacing our oil and gas reserves;
geographic concentration of our assets;
uncertainties in exploring for and producing oil and 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;

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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 gas industry;
our inability to retain and attract key personnel;
the effects of government regulation and permitting and other legal requirements;
costs associated with perfecting title for mineral rights in some of our properties; and
weaknesses in our internal controls.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2015 (the “2015 Annual Report”) and Part II, “Item 1A. Risk Factors” in this Quarterly Report.

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 they are made, whether as a result of new information, future events or otherwise.

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PART I — FINANCIAL INFORMATION

ITEM 1. Unaudited Consolidated Financial Statements

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

   
  December 31,
2015
  June 30,
2015
     (Unaudited)     
ASSETS
                 
Current Assets
                 
Cash and cash equivalents   $ 325,890     $ 756,848  
Accounts receivable
                 
Oil and natural gas sales     60,180       100,243  
Joint interest billings     20,600       12,433  
Other     22,667       43,513  
Prepaid expenses and other current assets     33,993       24,298  
Restricted cash     9,708       9,359  
Derivative financial instruments     61,169       22,229  
Total Current Assets     534,207       968,923  
Property and Equipment
                 
Oil and natural gas properties, net – full cost method of accounting, including $63.5 million and $436.4 million of unevaluated properties not being amortized at December 31, 2015 and June 30, 2015, respectively     1,096,466       3,570,759  
Other property and equipment, net     19,344       21,820  
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment     1,115,810       3,592,579  
Other Assets
                 
Derivative financial instruments           3,898  
Equity investments           10,835  
Restricted cash     46,024       32,667  
Other assets and debt issuance costs, net of accumulated amortization     68,196       81,927  
Total Other Assets     114,220       129,327  
Total Assets   $ 1,764,237     $ 4,690,829  
LIABILITIES
                 
Current Liabilities
                 
Accounts payable   $ 160,687     $ 156,339  
Accrued liabilities     117,847       155,306  
Asset retirement obligations     43,136       33,286  
Derivative financial instruments           2,661  
Current maturities of long-term debt     873       11,395  
Total Current Liabilities     322,543       358,987  
Long-term debt, less current maturities     3,622,508       4,597,037  
Asset retirement obligations     420,930       453,799  
Derivative financial instruments           1,358  
Other liabilities     15,319       8,370  
Total Liabilities     4,381,300       5,419,551  

 
 
See accompanying Notes to Consolidated Financial Statements.

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

   
  December 31,
2015
  June 30,
2015
     (Unaudited)     
Commitments and Contingencies (Note 15)
                 
Stockholders’ Deficit
                 
Preferred stock, $0.001 par value, 7,500,000 shares authorized at December 31, 2015 and June 30, 2015                  
7.25% Convertible perpetual preferred stock, 3,000 shares issued and outstanding at December 31, 2015 and June 30, 2015            
5.625% Convertible perpetual preferred stock, 797,759 and 812,759 shares issued and outstanding at December 31, 2015 and June 30, 2015, respectively     1       1  
Common stock, $0.005 par value, 200,000,000 shares authorized and 95,479,050 and 94,643,498 shares issued and outstanding at December 31, 2015 and June 30, 2015, respectively     476       472  
Additional paid-in capital     1,845,212       1,843,918  
Accumulated deficit     (4,462,752 )      (2,573,113 ) 
Total Stockholders’ Deficit     (2,617,063 )      (728,722 ) 
Total Liabilities and Stockholders’ Deficit   $ 1,764,237     $ 4,690,829  

 
 
See accompanying Notes to Consolidated Financial Statements.

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ENERGY XXI LTD
 
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, except per share information)
(Unaudited)

       
  Three Months Ended
December 31,
  Six Months Ended
December 31,
     2015   2014   2015   2014
Revenues
                                   
Oil sales   $ 139,698     $ 279,708     $ 318,606     $ 649,863  
Natural gas sales     16,615       31,801       40,100       66,362  
Gain on derivative financial instruments     28,302       191,462       83,732       248,187  
Total Revenues     184,615       502,971       442,438       964,412  
Costs and Expenses
                                   
Lease operating     88,358       119,366       182,980       261,951  
Production taxes     309       2,263       1,066       5,356  
Gathering and transportation     16,778       4,771       31,756       13,959  
Depreciation, depletion and amortization     121,567       175,155       245,591       334,295  
Accretion of asset retirement obligations     15,944       12,798       30,728       25,617  
Impairment of oil and natural gas properties     1,425,792             2,330,461        
Goodwill impairment           329,293             329,293  
General and administrative expense     29,015       27,745       51,204       54,169  
Total Costs and Expenses     1,697,763       671,391       2,873,786       1,024,640  
Operating Loss     (1,513,148 )      (168,420 )      (2,431,348 )      (60,228 ) 
Other Income (Expense)
                                   
Loss from equity method investees           (1,275 )      (10,746 )      (316 ) 
Other income, net     2,554       991       3,048       1,942  
Gain on early extinguishment of debt     290,296             748,574        
Interest expense     (90,234 )      (66,901 )      (193,452 )      (133,164 ) 
Total Other Income (Expense), net     202,616       (67,185 )      547,424       (131,538 ) 
Loss Before Income Taxes     (1,310,532 )      (235,605 )      (1,883,924 )      (191,766 ) 
Income Tax Expense     51       40,358       51       57,007  
Net Loss     (1,310,583 )      (275,963 )      (1,883,975 )      (248,773 ) 
Preferred Stock Dividends     2,810       2,870       5,664       5,742  
Net Loss Attributable to Common Stockholders   $ (1,313,393 )    $ (278,833 )    $ (1,889,639 )    $ (254,515 ) 
Loss per Share
                                   
Basic and diluted   $ (13.81 )    $ (2.97 )    $ (19.91 )    $ (2.71 ) 
Weighted Average Number of Common Shares Outstanding
                                   
Basic and diluted     95,075       93,993       94,926       93,913  

 
 
See accompanying Notes to Consolidated Financial Statements.

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ENERGY XXI LTD
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)

   
  Six Months Ended
December 31,
     2015   2014
Cash Flows From Operating Activities
                 
Net loss   $ (1,883,975 )    $ (248,773 ) 
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
                 
Depreciation, depletion and amortization     245,591       334,295  
Impairment of oil and natural gas properties     2,330,461        
Goodwill impairment           329,293  
Deferred income tax expense           56,447  
Gain on early extinguishment of debt     (748,574 )       
Change in fair value of derivative financial instruments     (42,162 )      (175,731 ) 
Accretion of asset retirement obligations     30,728       25,617  
Loss from equity method investees     10,746       316  
Amortization of debt issuance costs and other     11,117       5,615  
Deferred rent     4,577        
Stock-based compensation     987       2,632  
Changes in operating assets and liabilities
                 
Accounts receivable     70,873       33,819  
Prepaid expenses and other assets     (11,001 )      22,483  
Settlement of asset retirement obligations     (53,719 )      (53,960 ) 
Accounts payable and accrued liabilities     (55,573 )      (170,745 ) 
Net Cash Provided by (Used in) Operating Activities     (89,924 )      161,308  
Cash Flows from Investing Activities
                 
Acquisitions, net of cash     (2,797 )      (287 ) 
Capital expenditures     (75,784 )      (449,114 ) 
Insurance payments received     4,379        
Change in equity method investments           12,642  
Transfer from (to) restricted cash     (13,355 )      325  
Proceeds from the sale of properties     4,623       6,947  
Other     62       95  
Net Cash Used in Investing Activities     (82,872 )      (429,392 ) 
Cash Flows from Financing Activities
                 
Proceeds from the issuance of common and preferred stock, net of offering costs     312       2,059  
Dividends to shareholders – common           (22,548 ) 
Dividends to shareholders – preferred     (5,673 )      (5,744 ) 
Proceeds from long-term debt     1,121       1,011,948  
Payments on long-term debt     (225,004 )      (759,851 ) 
Payment of debt assumed in acquisition     (25,187 )       
Fees related to debt extinguishment     (2,080 )       
Debt issuance costs     (632 )      (2,302 ) 
Other     (1,019 )       
Net Cash Provided by (Used in) Financing Activities     (258,162 )      223,562  
Net Decrease in Cash and Cash Equivalents     (430,958 )      (44,522 ) 
Cash and Cash Equivalents, beginning of period     756,848       145,806  
Cash and Cash Equivalents, end of period   $ 325,890     $ 101,284  

 
 
See accompanying Notes to Consolidated Financial Statements.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — Organization, Summary of Significant Accounting Policies and Recent Accounting Pronouncements

Nature of Operations.  Energy XXI Ltd was incorporated in Bermuda on July 25, 2005. References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI Ltd and its wholly-owned subsidiaries. With our principal operating subsidiary headquartered in Houston, Texas, we are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and in the Gulf of Mexico Shelf (“GoM Shelf”). We are listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “EXXI”.

Principles of Consolidation and Reporting.  The accompanying consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

Interim Financial Statements.  The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the 2015 Annual Report.

Use of Estimates.  The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value estimates used in accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, 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.

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. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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

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

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

The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued. The guidance will be applied on a retrospective basis. We are currently evaluating the provisions of ASU 2015-03 and assessing the impact it may have on our consolidated financial position, results of operations or cash flows.

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

Note 2 — Liquidity and Capital Resources

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

As of December 31, 2015, we had cash and cash equivalents of approximately $326 million and approximately $122 million of available borrowing capacity under our second amended and restated first lien credit agreement (“First Lien Credit Agreement” or “Revolving Credit Facility” or “Revolver”). As of December 31, 2015, we had total indebtedness of $3,623.4 million, comprised of $150 million of secured indebtedness outstanding under our Revolving Credit Facility, $1.45 billion of 11% Senior Secured Second Lien Notes due 2020, $5 million in other secured indebtedness, $2,084 million of unsecured notes and net unamortized original issue discount of $65.6 million. Due to the continued decreases in commodity prices, the Company continues to incur significant losses and negative cash flows from operating activities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 2 — Liquidity and Capital Resources  – (continued)

As of December 31, 2015, we were in compliance with our financial covenants under the Revolving Credit Facility; however, based on current market conditions and depressed commodity prices, if we are unable to execute on one of the strategic alternatives discussed below and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio covenant under our Revolving Credit Facility for the quarter ending March 31, 2016. In addition, as part of our quarterly compliance certificates required under our Revolving Credit Facility and also as a condition to borrow additional funds or issue letters of credit under our Revolving Credit Facility, we must make certain representations, including representations about our solvency and we must remain in compliance with the financial ratios in our Revolving Credit Facility. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation.

We are evaluating various alternatives with respect to our Revolving Credit Facility, but there is no certainty that we will be able to implement any alternatives or otherwise resolve our covenant issues. If the lenders under the Revolving Credit Facility are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Revolving Credit Facility, and there is no assurance that we will reach an agreement with our lenders on any such amendment or waiver. Absent success in these pursuits, a resultant breach under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

We may face other impediments to accessing our available borrowing capacity under our Revolving Credit Facility. Borrowings under our First Lien Credit Agreement are also limited to a borrowing base based on oil and natural gas reserve values which are redetermined on a periodic basis. During the quarter ended December 31, 2015, we and our lenders completed our fall borrowing base redetermination with no changes to the existing borrowing base. If we experience the continuation of low oil and natural gas prices, or if they decline even further, we anticipate that our Revolving Credit Facility borrowing base and commitment amounts will likely be reduced in the spring of 2016 as part of our next borrowing base redetermination, which would adversely impact our liquidity. In addition, we would have to repay any outstanding indebtedness in excess of any reduced borrowing base.

In addition, in response to commodity price declines, our fiscal year 2016 capital budget was reduced to a current planned amount of $130 to $150 million, as compared to actual capital expenditures in fiscal year 2015 (excluding acquisition activity) of approximately $649 million. Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 2 — Liquidity and Capital Resources  – (continued)

of our unevaluated properties totaling to $336.5 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization. The curtailment of the development of our properties will eventually lead to a decline in our production and reserves. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operating activities and the value of our assets.

We may experience a further strain on our liquidity if Bureau of Ocean Energy Management (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 facilities, the abandonment of 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 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.

Beginning on January 11, 2016, our common stock has generally traded on NASDAQ at less than $1.00 per share. If at any time our common stock falls below the minimum bid price of $1.00 per share for 30 consecutive business days, NASDAQ will send a deficiency notice to the Company, advising that it has been afforded a “compliance period” of 180 calendar days to regain compliance with the applicable requirements. If the Company is unable to resolve its bid price deficiency during the applicable compliance period, NASDAQ Staff will issue a delisting letter. There is no assurance that the price of our common stock will comply with the requirements for continued listing of our shares on NASDAQ. A delisting of our common stock could constitute a “fundamental change” under the terms of our $400 million aggregate principal amount of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). If a Fundamental Change occurs at any time prior to the maturity of the 3.0% Senior Convertible Notes, each holder shall have the right to require the Company to repurchase all or part of such holder’s 3.0% Senior Convertible Notes in a principal amount thereof that is equal to $1,000 in principal amount or whole multiples thereof, on the date (the “Fundamental Change Repurchase Date”) specified by the Company that is not less than 20 nor more than 35 calendar days after the date of the Fundamental Change Company Notice at a repurchase price, payable in cash, equal to 100% of the principal amount of the 3.0% Senior Convertible Notes being repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date. We cannot assure that we would have adequate liquidity to fund a repurchase given the severe liquidity constraints of the Company. Such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

We had total indebtedness of $3,623.4 million as of December 31, 2015 and taking into account the bond repurchases completed subsequent to December 31, 2015, we had total indebtedness of $2,874.6 million as of February 15, 2016. We expect to have substantial interest payments due on our outstanding bonds in the next twelve months, totaling $247.8 million. In addition, the majority of our outstanding indebtedness will mature within the next ten years, with a substantial portion coming due in the next five years. All of the factors described above have placed considerable pressure on our ability to pay the principal and interest on our long-term debt, satisfy our other liabilities, continue our development activities to maintain and grow reserves and our ability to refinance our debt as it becomes due.

As a result of the commodity price decline and the Company’s substantial debt burden, absent a material improvement in oil and gas prices or a refinancing or restructuring of our debt obligations or other improvement in liquidity, the Company believes forecasted cash and expected available credit capacity will

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 2 — Liquidity and Capital Resources  – (continued)

not be sufficient to meet commitments as they come due for the next twelve months. This raises substantial doubt regarding the Company’s ability to continue as a going concern.

In February 2016, we engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise management and our Board of Directors (the “Board”) regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. We are also focused on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows.

As a result of the commodity price decline, we will continue to evaluate our ability to make the debt payments as they become due and to meet the additional supplemental bonding requirements of the BOEM and our surety companies’ requirements to provide additional cash collateral for such existing and future bonds in light of our liquidity constraints. On February 16, 2016, the Company elected to enter into the 30-day grace period under the terms of the indenture governing EPL Oil & Gas, Inc.’s (“EPL”) outstanding 8.25% Senior Notes due February 2018 (the “8.25% Senior Notes”) to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company will work with its debt holders regarding its ongoing effort to develop and implement a comprehensive plan to restructure its balance sheet.

The election to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes constitutes a default; however, it does not constitute an Event of Default under the indenture governing our 8.25% Senior Notes or the Revolving Credit Facility. As a result of this default, certain restrictions have been placed on the Company, including but not limited to, its ability to incur additional indebtedness, draw on the Revolving Credit Facility and issue additional letters of credit. The Company has 30 days to cure the default by making the required interest payment that was due on February 16, 2016. Alternatively, the Company may restructure the debt with its creditors. On March 17, 2016, if the interest payment default is not cured, the default would be considered an Event of Default and the trustee or the holders of at least 25% in aggregate principal amount of then outstanding 8.25% Senior Notes may declare the principal and accrued interest for all outstanding 8.25% Senior Notes due and payable immediately. An Event of Default would also trigger cross defaults in the Company’s other debt obligations. An Event of Default would have a material adverse effect on the Company’s liquidity, financial condition and results of operations.

Absent a material improvement in oil and gas prices or a refinancing or some restructuring of our debt obligations or other improvement in liquidity, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 3 — Acquisitions

Acquisition of interest in M21K

On August 11, 2015, pursuant to a stock purchase agreement (the “M21K Purchase Agreement”) between Energy XXI M21K, LLC (“EXXI M21K”), in which we owned 20% interest, and Energy XXI GOM, LLC (“EXXI GOM”), an indirect wholly owned subsidiary of Energy XXI, we acquired all of the remaining equity interests of M21K, LLC (“M21K”) for consideration consisting of the assumption of all obligations and liabilities of M21K including approximately $25.2 million associated with M21K’s first lien credit facility, which was required to be paid at closing (the “M21K Acquisition”). The sellers retained certain overriding royalty interests applicable only to the extent that production proceeds during any calendar month average in excess of $65.00/Bbl WTI and $3.50/MMbtu Henry Hub and limited to a term of four years or an aggregate amount of $20 million, whichever occurs earlier. In addition, with respect to the Eugene Island 330 and South Marsh Island 128 fields, in the event we sell our interest in one or both of these fields, the overriding royalty interests with respect to such sold field shall terminate; provided, however if such sale occurs within four years of the effective date of the M21K Purchase Agreement and the consideration received for such sale is greater than the allocated value for such field as specified in the M21K Purchase Agreement, then we are obligated to pay an amount equal to 20% of the portion of the consideration received in excess of the specified allocated value of such field. Prior to this transaction which is effective as of August 1, 2015, we had owned a 20% interest in M21K through our investment in EXXI M21K. See Note 5 — Equity Method Investments.

The following table presents the preliminary 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.

Note 4 — Property and Equipment

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

   
  December 31,
2015
  June 30,
2015
Oil and natural gas properties
                 
Proved properties   $ 9,714,627     $ 9,243,737  
Less: accumulated depreciation, depletion, amortization and impairment     (8,681,623 )      (6,109,335 ) 
Proved properties, net     1,033,004       3,134,402  
Unevaluated properties     63,462       436,357  
Oil and natural gas properties, net     1,096,466       3,570,759  
Other property and equipment     44,233       45,941  
Less: accumulated depreciation     (24,889 )      (24,121 ) 
Other property and equipment, net     19,344       21,820  
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment   $ 1,115,810     $ 3,592,579  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 4 — Property and Equipment  – (continued)

At December 31, 2015, the Company’s investment in unevaluated properties primarily relates to the fair value of unproved oil and natural gas properties acquired in oil and gas property acquisitions (primarily the acquisition of EPL Oil & Gas, Inc. (“EPL”) on June 3, 2014 (the “EPL Acquisition”)). Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of (i) a determination as to whether there are any proved reserves related to the properties, 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 have transferred such amounts to the full cost pool, subject to amortization.

Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling.

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. For the three and six months ended December 31, 2015, our ceiling test computation resulted in impairments of our oil and natural gas properties of $1,425.8 million and $2,330.5 million, respectively. If the current low commodity price environment or downward trend in oil and natural gas prices continues, we will incur further impairment to our full cost pool in fiscal 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

Note 5 — Equity Method Investments

Prior to the M21K Acquisition on August 11, 2015 discussed previously in Note 3 — Acquisitions, 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. Energy XXI Gulf Coast, Inc. (“EGC”), an indirect wholly owned subsidiary of Energy XXI 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 3 —  Acquisitions and Note 13 — Related Party Transactions.

We recorded an equity loss of $0 and $10.7 million for the three and six months ended December 31, 2015, respectively. We recorded an equity loss of $1.3 million and $0.3 million for the three and six months ended December 31, 2014, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt

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

   
  December 31,
2015
  June 30,
2015
Revolving Credit Facility   $ 150,000     $ 150,000  
11.0% Senior Secured Second Lien Notes due 2020     1,450,000       1,450,000  
8.25% Senior Notes due 2018     480,244       510,000  
6.875% Senior Notes due 2024     143,993       650,000  
3.0% Senior Convertible Notes due 2018     400,000       400,000  
7.5% Senior Notes due 2021     238,071       500,000  
7.75% Senior Notes due 2019     101,077       250,000  
9.25% Senior Notes due 2017     720,585       750,000  
4.14% Promissory Note due 2017     4,120       4,343  
Debt premium, 8.25% Senior Notes due 2018(1)     21,218       29,459  
Original issue discount, 11.0% Notes due 2020     (46,989 )      (51,104 ) 
Original issue discount, 3.0% Senior Convertible Notes due 2018     (39,806 )      (45,782 ) 
Derivative instruments premium financing           10,647  
Capital lease obligations     868       869  
Total debt     3,623,381       4,608,432  
Less current maturities     873       11,395  
Total long-term debt   $ 3,622,508     $ 4,597,037  

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

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 6.875% Senior Notes due 2024, $261.9 million of 7.5% Senior Notes due 2021, $148.9 million of 7.75% Senior Notes due 2019, $29.8 million of 8.25% Senior Notes due 2018 and $29.4 million of 9.25% Senior Notes due 2017. We repurchased these notes in open market transactions at a total cost of approximately $213.1 million, and we recorded a gain on the repurchases totalling approximately $748.6 million, net of associated debt issuance costs and certain other expenses. All of the repurchased notes were cancelled. Subsequent to December 31, 2015, we repurchased approximately $737.7 million of our unsecured notes in open market transactions at a total price of approximately $19.2 million, including $16.4 million of accrued interest, reducing our total indebtedness to approximately $2,874.6 million as of February 15, 2016.

Maturities of long-term debt as of December 31, 2015 are as follows (in thousands):

 
Twelve Months Ending December 31,
2016   $ 873  
2017     1,204,730  
2018     550,214  
2019     101,077  
2020     1,450,000  
Thereafter     382,064  
       3,688,958  
Less: Net original issue discount and debt premium     (65,577 ) 
Total debt   $ 3,623,381  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

Revolving Credit Facility

The Revolving Credit Facility was entered into by EGC in May 2011 and underwent its Twelfth Amendment to the First Lien Credit Agreement on November 30, 2015 (the “Twelfth Amendment”) and its Eleventh Amendment and Waiver to the First Lien Credit Agreement was on July 31, 2015 (the “Eleventh Amendment”). The Revolving Credit Facility, as amended, has a maximum facility amount and borrowing base of $500 million, of which such amount $150 million is the borrowing base under the sub-facility established for EPL. These respective borrowing bases were set in accordance with the regular annual process for determination of the borrowing bases and the borrowing bases are to remain in effect until the next redetermination thereof under the terms of the First Lien Credit Agreement. Borrowings under our First Lien Credit Agreement are also limited to a borrowing base based on oil and natural gas reserve values, which are redetermined on a periodic basis. During the quarter ended December 31, 2015, we and our lenders completed our fall borrowing base redetermination with no changes to the existing borrowing base at $500 million, and the lenders temporarily relaxed the requirements of certain financial covenants under the Twelfth Amendment as described below. The scheduled date of maturity of the First Lien Credit Agreement is April 9, 2018, provided however that the maturity date will accelerate to a date 210 days prior to the date of maturity of EGC’s outstanding 9.25% unsecured notes due December 2017 (the “9.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or to a date 210 days prior to the date of maturity of EPL’s outstanding 8.25% Senior Notes due February 2018 (the “8.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or otherwise to a date that is 180 days prior to the date of maturity of any other permitted second lien or permitted third lien indebtedness or certain permitted unsecured indebtedness or any refinancings of such indebtedness if such indebtedness would come due prior to April 9, 2018. If we experience the continuation of low oil and natural gas prices, or if they decline even further, we anticipate that our Revolving Credit Facility borrowing base and commitment amounts will likely be reduced in the spring of 2016 as part of our next borrowing base redetermination, which would adversely impact our liquidity. In addition, we may have to repay any outstanding indebtedness in excess of any reduced borrowing base.

Borrowings are limited to a borrowing base based on oil and natural gas reserve values which are re-determined on a periodic basis. The Revolving Credit Facility is secured by mortgages on at least 90% of the value of EGC and its subsidiaries’ (other than EPL and its subsidiaries until they shall have become guarantors of the EGC indebtedness under the First Lien Credit Agreement) proved reserves and proved developed producing reserves, but with the threshold for such properties of EPL and its subsidiaries (until they shall have become guarantors of the EGC indebtedness under the First Lien Credit Agreement) at 85%. Additionally, as a result of the Twelfth Amendment, EPL is required to maintain $30 million of restricted cash in an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement.

Currently, the facility bears interest based on the borrowing base usage, at either the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. The applicable commitment fee under the facility is 0.50%.

The First Lien Credit Agreement contains certain restrictions on the prepayment and repayment of outstanding note indebtedness of EGC and its subsidiaries, including the prohibition on using proceeds from credit extensions under the First Lien Credit Agreement for any such prepayment or repayment and the requirement that EGC have net liquidity at the time thereof of at least $250 million. In addition, EGC is required to have pro forma net liquidity of $250 million at the time of any refinancing of outstanding indebtedness.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

Under the First Lien Credit Agreement, EGC’s rights to make distributions to its shareholders and pay dividends to parent entities (including ultimately to Energy XXI) are very limited. Generally, EGC is only permitted to make such distributions for income tax liabilities arising for such other entities that relate to the income attributable to EGC and its subsidiaries, general and administrative expenses not to exceed $2 million in any fiscal year and for payment of insurance premiums in regards to affiliated party insurance agreements. Substantially all of the net assets of the Company’s subsidiaries are restricted.

Lender consent is required for any asset disposition that would have the effect of reducing the borrowing base by more than $5 million in the aggregate. The Eleventh Amendment waived certain provisions of the First Lien Credit Agreement to permit the M21K Acquisition as well as an additional minor acquisition and disposition.

The First Lien Credit Agreement requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. EGC is subject to the following financial covenants on a consolidated basis: (a) a minimum current ratio of no less than 1.0 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 as of the end of the fiscal quarter ended December 31, 2015, and increasing to 4.75 to 1.0 starting March 31, 2016, to 5.25 to 1.0 starting June 30, 2016 and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter. In addition, EGC is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 beginning with the fiscal quarter ending March 31, 2017. In addition, EPL is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 beginning with the fiscal quarter ending March 31, 2017. If EPL’s 8.25% Senior Notes are no longer outstanding and certain other conditions are met, EGC and EPL will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 4.75 to 1.0 as of the end of each fiscal quarter beginning with the fiscal quarter ending March 31, 2016, increasing to 5.25 to 1.0 starting June 30, 2016 and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter, and (c) a minimum current ratio of no less than 1.0 to 1.0.

Additionally, the following changes became effective upon the execution of the Twelfth Amendment:

Modification of triggers that require EPL and its subsidiaries to provide guarantees of the indebtedness of EGC and its subsidiaries and grant liens on the assets of EPL and its subsidiaries to secure such guarantees. Under such modifications, such guarantees and security will be required upon the earlier of EPL’s retirement of its obligations in respect of its outstanding 8.25% Senior Notes and amendments to covenant restrictions under such notes that eliminate restrictions on the ability of EPL and its subsidiaries to guarantee the indebtedness of EGC and its subsidiaries and grant liens on the assets of EPL and its subsidiaries to secure such guarantees (even if such notes have not been refinanced or defeased).
Suspending the maximum net secured leverage ratio covenant with respect to EGC and its subsidiaries (other than EPL and its subsidiaries) to begin on the fiscal quarter ending March 31, 2017 rather than March 31, 2015.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

Suspending the maximum net secured leverage ratio covenant with respect to EPL and its subsidiaries to begin on the fiscal quarter ending March 31, 2017 rather than March 31, 2015.
Modifying the maximum net secured leverage covenant with respect to EGC and its subsidiaries to be 3.75:1.00 as of the end of each fiscal quarter beginning with the fiscal quarter ended September 30, 2015, increasing to 4.75:1.00 starting March 31, 2016 and to 5.25:1.00 starting June 30, 2016, and decreasing to 5.00:1.00 beginning June 30, 2017 and thereafter.

As of December 31, 2015, we had $150.0 million in borrowings and $227.8 million in letters of credit issued under the First Lien Credit Agreement and we were in compliance with all covenants thereunder. Due to current market conditions and depressed commodity prices, we engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise management and our Board regarding the potential strategic alternatives to address our liquidity issues and high debt levels. Based on current market conditions and depressed commodity prices, if we are unable to execute on one of the strategic alternatives being evaluated and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio under our Revolving Credit Facility for the quarter ending March 31, 2016. Due to our election on February 16, 2016 to enter into the 30-day grace period for making interest payment under the terms of the indenture governing EPL’s outstanding 8.25% Senior Notes, certain restrictions, as fully described below under the caption 8.25% Senior Notes Due 2018, have been placed on the Company. In addition, as part of our quarterly compliance certificates required under our Revolving Credit Facility and also as a condition to borrow funds or issue letters of credit under our Revolving Credit Facility, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in our Revolving Credit Facility. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation.

We are evaluating various alternatives with respect to our Revolving Credit Facility, but there is no certainty that we will be able to implement any alternatives or otherwise resolve our covenant issues. If the lenders under the Revolving Credit Facility are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we will be forced to repay or refinance amounts then outstanding under the Revolving Credit Facility, and there is no assurance that we will reach an agreement with our lenders on any such amendment or waiver. Absent success in these pursuits, a resultant breach under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

11.0% Senior Secured Second Lien Notes Due 2020

On March 12, 2015, EGC issued $1.45 billion in aggregate principal amount of 11.0% senior secured second lien notes due March 15, 2020 (the “11.0% Notes”) pursuant to the Purchase Agreement (the “Purchase Agreement”) by and among EGC, Energy XXI Ltd, our ultimate parent company (the “Parent”), Energy XXI USA, Inc. (“EXXI USA”) and certain of EGC’s wholly owned subsidiaries (together with the Parent and EXXI USA, the “Guarantors”), and Credit Suisse Securities (USA) LLC, Deutsche Bank

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

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 $1.35 billion in the offering after deducting the Initial Purchasers’ discount and direct offering costs. The 11.0% Notes were sold to investors at a discount of 96.313% of principal, for a yield to maturity at issuance of 12.0%. The 11.0% 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 11.0% Notes and the related guarantees have not been, and will not be, registered under the Securities Act or the securities laws of any other jurisdiction. The 11.0% Notes bear interest from the date of their issuance at an annual rate of 11.0% with interest due semi-annually, in arrears, on March 15th and September 15th, beginning September 15, 2015. EGC incurred underwriting and direct offering costs of $41.7 million which were recorded as debt issuance costs. The effective interest rate on the 11.0% Notes is approximately 12.8%, reflecting amortization of the Initial Purchasers’ discount of $53.5 million as well as the amortization of debt issuance costs.

The 11.0% 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 11.0% Notes are secured by second-priority liens on substantially all of EGC and its subsidiary guarantors’ assets and all of EXXI USA’s equity interests in EGC, in each case to the extent such assets secure our Revolving Credit Facility. In the future, the 11.0% Notes may be guaranteed by certain of EGC’s material domestic restricted subsidiaries that incur or guarantee certain indebtedness, including, upon the occurrence of certain events, some or all of EPL and its subsidiaries. The liens securing the 11.0% Notes and the related guarantees are contractually subordinated to the liens on such assets securing our Revolving Credit Facility and any other priority lien debt, to the extent of the value of the collateral securing such obligations, pursuant to the terms of an intercreditor agreement, and to certain other secured indebtedness, to the extent of the value of the assets subject to the liens securing such indebtedness.

The 11.0% Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain of EGC’s future subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2015 Indenture. Although the 11.0% Notes are guaranteed by the Parent and EXXI USA, the Parent and EXXI USA will not, subject to certain exceptions, be subject to the restrictive covenants in the 2015 Indenture.

On or after September 15, 2017, EGC will have the right to redeem all or some of the 11.0% Notes at specified redemption prices (initially 108.25% of the principal amount, declining to par on or after July 15, 2019), plus accrued and unpaid interest. Prior to September 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 11.0% Notes originally issued at a price equal to 111.0% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to September 15, 2017, EGC may redeem all or part of the 11.0% Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC will be required to offer to purchase all outstanding 11.0% Notes if a “triggering event” occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a “triggering event” will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes, if on such date the aggregate outstanding principal amount of all such notes that have not been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes, if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes that shall not have been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million. As a result of our bond repurchases subsequent to December 31, 2015, we have reduced the principal amount of the 8.25% Senior Notes and the 9.25% Senior Notes outstanding to $213.7 million and $249.5 million, respectively, eliminating this springing maturity in the 11.0% Notes.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

If a change of control, as defined in the 2015 Indenture, occurs, each holder of the 11.0% Notes will have the right to require EGC to repurchase all or any part of their 11.0% Notes at a price equal to 101% of the aggregate principal amount plus accrued and unpaid interest.

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

8.25% Senior Notes Due 2018

On June 3, 2014, EGC assumed the 8.25% Senior Notes in the EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL’s obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

On February 16, 2016, the Company elected to enter into the 30-day grace period under the terms of the indenture governing the outstanding 8.25% Senior Notes due February 2018 to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company will work with its debt holders regarding its ongoing effort to develop and implement a comprehensive plan to restructure its balance sheet.

The election to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes constitutes a default; however, it does not constitute an Event of Default under the indenture governing the 8.25% Senior Notes or the Revolving Credit Facility. As a result of this default, certain restrictions have been placed on the Company, including but not limited to, its ability to incur additional indebtedness, draw on the Revolving Credit Facility and issue additional letters of credit. The Company has 30 days to cure the default by making the required interest payment that was due on February 16, 2016. Alternatively, the Company may restructure the debt with its creditors. On March 17, 2016, if the interest payment default is not cured, the default would be considered an Event of Default and the trustee or the holders of at least 25% in aggregate principal amount of then outstanding 8.25% Senior Notes may declare the principal and accrued interest for all outstanding 8.25% Senior Notes due and payable immediately. An Event of Default would also trigger cross defaults in the Company’s other debt obligations. An Event of Default would have a material adverse effect on the Company’s liquidity, financial condition and results of operations. Please see Note 2 — Liquidity and Capital Resources for more information.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

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.

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

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

3.0% Senior Convertible Notes Due 2018

On November 18, 2013, the Parent 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 have been capitalized and are being amortized over the life of the 3.0% Senior Convertible Notes. The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the election of the Parent, based on an initial conversion rate of 24.7523 shares of common stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common stock). The conversion rate, and accordingly the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.

Upon conversion, the Parent will be obligated to pay or deliver, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at its election. If the conversion obligation is satisfied solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture governing the 3.0% Senior Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture governing the 3.0% Senior Convertible Notes). Upon any

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

conversion, subject to certain exceptions, holders of the 3.0% Senior Convertible Notes will receive interest, payable in cash, shares of common stock or a combination of cash and shares of common stock paid or delivered, as the case may be.

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

If the Parent undergoes a fundamental change (as defined in the indenture governing the 3.0% Senior Convertible Notes) prior to maturity, holders of the 3.0% Senior Convertible Notes will have the right, at their option, to require the Parent to repurchase for cash some or all of their notes at a repurchase price equal to 100% of the principal amount of the notes being repurchased, plus accrued and unpaid interest (including additional interest, if any) to, but excluding, the fundamental change repurchase date. Such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

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 is being amortized as an increase in interest expense over the life of the 3.0% Senior Convertible Notes.

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.

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

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

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

7.75% Senior Notes Due 2019

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.

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 7.75% Senior Notes.

9.25% Senior Notes Due 2017

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.

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 9.25% Senior Notes.

4.14% Promissory Note

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

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of December 31, 2015 and June 30, 2015, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $0 and $10.6 million, respectively.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

Interest Expense

For the three and six months ended December 31, 2015 and 2014, interest expense consisted of the following (in thousands):

       
  Three Months Ended December 31,   Six Months Ended December 31,
     2015   2014   2015   2014
Revolving Credit Facility   $ 3,751     $ 7,482     $ 7,561     $ 14,375  
11.0% Senior Secured Second Lien Notes due 2020     40,202             80,405        
8.25% Senior Notes due 2018     10,130       10,519       20,649       21,038  
6.875% Senior Notes due 2024     4,169       11,172       15,201       22,344  
3.0% Senior Convertible Notes due 2018     3,024       3,024       6,049       6,049  
7.50% Senior Notes due 2021     4,521       9,375       12,306       18,750  
7.75% Senior Notes due 2019     2,197       4,844       5,958       9,688  
9.25% Senior Notes due 2017     16,761       17,344       34,105       34,688  
4.14% Promissory Note due 2017     45       47       89       99  
Amortization of debt issue cost – Revolving Credit Facility     630       1,080       1,306       2,057  
Accretion of original debt issue discount, 11.0% Notes due 2020     2,090             4,114        
Amortization of debt issue cost – 11.0% Notes due 2020     1,688             3,323        
Amortization of fair value premium – 8.25% Senior Notes due 2018     (3,282 )      (2,570 )      (6,723 )      (5,104 ) 
Amortization of debt issue cost – 6.875% Senior Notes due 2024     113       282       395       563  
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018     3,015       2,806       5,976       5,561  
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018     386       359       765       712  
Amortization of debt issue cost – 7.50% Senior Notes due 2021     125       262       355       525  
Amortization of debt issue cost – 7.75% Senior Notes due 2019     45       97       130       194  
Amortization of debt issue cost – 9.25% Senior Notes due 2017     682       551       1,385       1,103  
Derivative instruments financing and other     (58 )      227       103       522  
     $ 90,234     $ 66,901     $ 193,452     $ 133,164  

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 7 — Asset Retirement Obligations

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

 
Balance at June 30, 2015   $ 487,085  
Liabilities acquired     66,700  
Liabilities incurred and true-up to liabilities settled     7,933  
Liabilities settled     (53,719 ) 
Revisions*     (74,661 ) 
Accretion expense     30,728  
Total balance at December 31, 2015     464,066  
Less: current portion     43,136  
Long-term balance at December 31, 2015   $ 420,930  

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

Note 8 — Derivative Financial Instruments

We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use various instruments including financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars, with only zero-cost collars and three-way collars outstanding at December 31, 2015. 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 statements of operations.

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 8 — Derivative Financial Instruments  – (continued)

As of December 31, 2015, we had the following net open crude oil derivative positions:

         
        Weighted Average Contract Price
         Volumes (MBbls)   Collars/Put
Remaining Contract Term   Type of Contract   Index   Floor   Ceiling
January 2016 – June 2016     Collars       NYMEX-WTI       2,548     $ 51.43     $ 74.70  
July 2016 – December 2016     Collars       NYMEX-WTI       2,576       51.43       74.70  

As of December 31, 2015, we had the following net open natural gas derivative position:

           
        Weighted Average Contract Price
         Volumes (MMBtu)   Collars/Put
Remaining Contract Term   Type of Contract   Index   Sub Floor   Floor   Ceiling
January 2016 – April 2016     Three-Way Collars       NYMEX-HH       1,515     $ 2.43     $ 2.93     $ 4.12  

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

               
  Asset Derivative Instruments   Liability Derivative Instruments
     December 31, 2015   June 30, 2015   December 31, 2015   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     $ 62,557       Current     $ 51,024       Current     $ 1,388       Current     $ 31,456  
       Non-Current             Non-Current       11,980       Non-Current             Non-Current       9,440  
Total gross derivative financial instruments subject to enforceable master netting agreement           62,557             63,004             1,388             40,896  
Derivative financial instruments     Current       (1,388 )      Current       (28,795 )      Current       (1,388 )      Current       (28,795 ) 
       Non-Current             Non-Current       (8,082 )      Non-Current             Non-Current       (8,082 ) 
Gross amounts offset in Balance Sheets           (1,388 )            (36,877 )            (1,388 )            (36,877 ) 
Net amounts presented in Balance Sheets     Current       61,169       Current       22,229       Current             Current       2,661  
       Non-Current             Non-Current       3,898       Non-Current             Non-Current       1,358  
           $ 61,169           $ 26,127           $           $ 4,019  

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

       
  Three Months Ended
December 31,
  Six Months Ended
December 31,
Gain (loss) on derivative financial instruments   2015   2014   2015   2014
Cash settlements, net of purchased put premium amortization   $ 22,828     $ 44,954     $ 41,570     $ 43,220  
Proceeds from monetizations           25,873             29,236  
Change in fair value     5,474       120,635       42,162       175,731  
Total gain on derivative financial instruments   $ 28,302     $ 191,462     $ 83,732     $ 248,187  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 8 — Derivative Financial Instruments  – (continued)

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our 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, 2015, we had no deposits for collateral with our counterparties.

Note 9 — Income Taxes

We are a Bermuda company and are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure. We estimate our annual effective tax rate for the current fiscal year and apply it to interim periods. Currently, our estimated annual effective tax/(benefit) rate is zero. Our actual effective tax/(benefit) rate for the three and six months ended December 31, 2015 was also zero. The variance from the U.S. statutory rate of 35% is primarily due to continued recorded and forecast losses that, based on present circumstances, will not result in us recording a current income tax benefit. Rather, all increases in net deferred tax assets (primarily related to net operating loss (“NOL”) carryovers net of deferred tax liability from oil and natural gas properties’ net book carrying values exceeding their corresponding tax bases) will be completely offset by increases in valuation allowances. As required by ASC Topic 740-270, Income Taxes: Interim Reporting, we forecast our tax position for the year, and may not record an additional tax benefit in an interim period unless we believe that we would be allowed to record a net deferred tax asset at the end of the year. At this time, we do not have such a belief (due to a preponderance of negative evidence as to future realizability) and accordingly reflect a current deferred tax benefit of zero. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.

Our Bermuda companies continue to record income tax expense reflecting 30% U.S. withholding tax on any interest (and interest equivalent) accrued on indebtedness of the U.S. companies held by the Bermuda companies. We have accrued an additional withholding obligation of $5.2 million for the six months ended December 31, 2015. During the six months ended December 31, 2015, we have not made any cash withholding tax payments on management fees paid to our Bermuda entities. We record the 30% withholding tax as a separate line item which is offset by other U.S. federal deferred tax assets in the consolidated financial statements to arrive at the zero net deferred tax asset/liability amounts presented.

We have historically paid no significant U.S. cash income taxes due to the election to expense intangible drilling costs and the presence of our NOLs. In light of the Company’s recent activity in repurchasing certain indebtedness at a discount (see Note 6), gains on these repurchases are includable in taxable income of the Company for the current year, however the Company believes that it is more-likely than not entitled to exclude these gains from the current taxable income under an allowable statutory exclusion. The Alternative Minimum Tax (“AMT”) only allows offset of 90% of AMT income by NOL carryovers (with certain limited exceptions for 2009 and 2010 generated NOLs), with the balance of income being taxed at 20%. We presently do not expect to make any cash AMT payments during this fiscal year. If any such AMT payments were required, we believe that, under present circumstances, we would not be able to record a net deferred tax asset for these payments, even though they result in a Minimum Tax Credit usable against future regular income tax with no expiration period. As such, we believe that any current-year cash AMT payments would have a negative impact on earnings. We revise our ongoing estimated AMT obligation each quarter during the year and revise our expected income tax rate and cash tax payment disclosure accordingly.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 10 — Stockholders’ Equity

Common Stock

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

Beginning on January 11, 2016, our common stock has generally traded on NASDAQ at less than $1.00 per share. If at any time our common stock falls below the minimum bid price of $1.00 per share for 30 consecutive business days, NASDAQ will send a deficiency notice to the Company, advising that it has been afforded a “compliance period” of 180 calendar days to regain compliance with the applicable requirements. If we are unable to resolve our bid price deficiency during the applicable compliance period, NASDAQ Staff will issue a delisting letter. This matter is discussed further in “Item 1A. Risk Factors  — If the trading price of our common stock fails to comply with the continued listing requirements of NASDAQ, we could face possible delisting. NASDAQ delisting could materially adversely affect the market for our shares.”

Late in fiscal year 2015, our Board of Directors decided to suspend the declaration of quarterly dividends on our common stock for the foreseeable future. During the three and six months ended December 31, 2014, we paid cash dividends of $0.12 per share to holders of our common stock.

As of December 31, 2015, $83.2 million remains available for repurchases under the share repurchase program approved by our Board of Directors in May 2013. We have suspended the repurchase program indefinitely to reduce our capital needs.

Preferred Stock

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

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

Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock may be paid in cash, shares of our common stock, or a combination thereof. If we elect to make payment in shares of common stock, such shares shall be valued for such purposes at 95% of the market value of our common stock as determined on the second trading day immediately prior to the record date for such dividend.

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

The 5.625% Preferred Stock is convertible into 9.8353 shares of our common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 5.625% Preferred Stock Certificate of Designation. At December 31, 2015, the conversion rate was 10.4765 common shares per preferred share. On or after December 15, 2013, we may cause the 5.625% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of our

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 10 — Stockholders’ Equity  – (continued)

common stock equals or exceeds 130% of the then-prevailing conversion price. The 5.625% Preferred Stock became callable beginning December 15, 2013 if our common stock trading price exceeds $32.45 per share for 20 of 30 consecutive trading days.

The 7.25% Preferred Stock is convertible into 8.77192 shares of our common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 7.25% Preferred Stock Certificate of Designation. At December 31, 2015, the conversion rate was 9.3439 common shares per preferred share. On or after December 15, 2014, we may cause the 7.25% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of our common stock equals or exceeds 150% of the then-prevailing conversion price.

Conversions of Preferred Stock

During the six months ended December 31, 2015, we canceled and converted 15,000 shares of our 5.625% Preferred Stock into a total of 157,148 shares of common stock using a conversion rate of 10.4765 common shares per preferred share.

During the six months ended December 31, 2014, we canceled 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 six months ended December 31, 2014, we also canceled 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.

Note 11 — Supplemental Cash Flow Information

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

   
  Six Months Ended
December 31,
     2015   2014
Cash paid for interest   $ 195,935     $ 117,342  
Cash paid for income taxes     150       560  

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

   
  Six Months Ended
December 31,
     2015   2014
Financing of insurance premiums   $     $ 2,148  
Derivative instruments premium financing           7,305  
Changes in capital expenditures accrued in accounts payable     30,356       113,814  
Changes in asset retirement obligations     (28 )      21,912  

Note 12 — Employee Benefit Plans

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 12 — Employee Benefit Plans  – (continued)

At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due to employees will be settled in either common shares or cash. Historically, we have settled all vesting Restricted Stock Units awards in cash and accordingly they are accounted for under the liability method. The July 2015 vesting of the July 2014, 2013, and 2012 Performance Unit awards were also settled in cash; however, future vesting of the Performance Units may be settled in common stock at the discretion of our Board of Directors. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable.

Changes for Fiscal 2016 Performance Unit Grants.  For the performance unit awards granted in fiscal 2016, the Total Shareholder Return (“TSR Modifier”) is linked to the performance of the Company’s common stock, and the price of the Company’s common stock is calculated using the simple average of the closing prices of the Company’s stock for the period of twenty business days ending on the last business day of June 2018 (“TSR Stock Price”). The number of units that cliff vest on June 30, 2018 will be the number of performance unit awards granted multiplied by TSR modifier which ranges from 0% to 300% for the TSR Stock Price range of less than $3 to $12. Prior to vesting, the holder of the granted units is not entitled to any rights as a holder of the common stock of the Company and is prohibited from selling, transferring or alienating or hypothecating the granted units. Within 30 days of vesting, the Company will issue stock or at the Company’s discretion the holder may be paid cash for the vested units.

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

       
  Three Months Ended
December 31,
  Six Months Ended
December 31,
     2015   2014   2015   2014
Restricted Stock Units   $ 3,104     $ 3,008     $ 24     $ 3,978  
Performance Units     850       (433 )      1,161       (5,608 ) 
Total compensation expense recognized   $ 3,954     $ 2,575     $ 1,185     $ (1,630 ) 

As of December 31, 2015, we had 8,195,246 unvested Restricted Stock Units and 344,146 Time-Based Performance Units and 2,190,546 TSR Performance Based Units.

Note 13 — 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 by M21K for the EP Energy property acquisition estimated at $65 million and $1.8 million, respectively. For the LLOG Exploration acquisition, we had guaranteed payment of asset retirement obligations by M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchase, we had guaranteed payment of asset retirement obligation by 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 month ended July 31, 2015, we received $0.3 million related to such guarantees. For the three and six months ended December 31, 2014, we received $1.0 million and $1.9 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 month ended July 31, 2015, we received management fees of $0.2 million. For the three and six months ended December 31, 2014, we received management fees of $0.5 million and $1.4 million, respectively. See Note 3 — Acquisitions.

Effective January 15, 2015, our Board of Directors appointed one of its members, James LaChance, to serve as our interim Chief Strategic Officer. In that position, Mr. LaChance pursued discussions with our lenders and noteholders to improve our available capital, leverage ratios and average debt maturity, as directed

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 13 — Related Party Transactions  – (continued)

by our Chief Executive Officer, in consultation with the Board. Mr. LaChance’s duties as interim Chief Strategic Officer were separate from, and in addition to, his responsibilities as a member of the Board of Directors. In light of the significant increase in the amount of time Mr. LaChance was required to spend performing in this new role, we and Mr. LaChance entered into an interim Chief Strategic Officer consulting agreement (the “Consulting Agreement”), with an effective date of January 15, 2015. Under the Consulting Agreement, Mr. LaChance was paid $200,000 per month for his services as interim Chief Strategic Officer. The Consulting Agreement expired on July 15, 2015. During the six months ended December 31, 2015, Mr. LaChance earned and was paid consulting fees of $0.1 million under the Consulting Agreement.

In accordance with the discretionary portion of a success fee payable in connection with the Consulting Agreement, the Board of Directors awarded Mr. LaChance the full $1 million amount on October 15, 2015. Fifty percent of this amount was paid in cash and the other fifty percent was paid in the form of 231,482 RSUs, based on a price of $2.16 per share, which was the closing price of our common stock on October 15, 2015.

On October 9, 2015, the Board determined that the positions of Chief Executive Officer and Chairman of the Board should be held by two different individuals. As a result of that determination, the Board elected Mr. LaChance to serve as Chairman of the Board, effective as of October 15, 2015, to serve in such capacity until the earlier of his resignation or removal. Mr. LaChance will not receive any compensation for serving as Chairman of the Board, other than pursuant to director compensation programs that are applicable to other non-employee directors.

Note 14 — Loss per Share

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

       
  Three Months Ended
December 31,
  Six Months Ended
December 31,
     2015   2014   2015   2014
Net loss   $ (1,310,583 )    $ (275,963 )    $ (1,883,975 )    $ (248,773 ) 
Preferred stock dividends     2,810       2,870       5,664       5,742  
Net loss attributable to common stockholders   $ (1,313,393 )    $ (278,833 )    $ (1,889,639 )    $ (254,515 ) 
Weighted average shares outstanding for basic and diluted EPS     95,075       93,993       94,926       93,913  
Loss per share
                                   
Basic and diluted   $ (13.81 )    $ (2.97 )    $ (19.91 )    $ (2.71 ) 

For the three and six months ended December 31, 2015, 9,021,827 and 9,101,829 common stock equivalents were excluded from the diluted average shares due to an anti-dilutive effect. For the three and six months ended December 31, 2014, 8,542,361 and 8,543,120, respectively, common stock equivalents were excluded from the diluted average shares due to an anti-dilutive effect.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 15 — Commitments and Contingencies

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

Letters of Credit and Performance Bonds.  As of December 31, 2015, we had $225 million in letters of credit to third parties relating to assets in the Gulf of Mexico and $405.7 million of performance bonds outstanding. As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (OCS), approximately $244.0 million of our performance bonds are lease and/or area bonds issued to the BOEM (including $65.4 million associated with our August 2015 acquisition of the remaining equity interests in M21K) that the BOEM has access to and assure our commitment to comply with the terms and conditions of those leases. We also maintain approximately $161.7 million in performance bonds issued to predecessor third party assignors rather than to the BOEM 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 waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015 and December 2015, we reached agreements with the BOEM with respect to which we provided $150 million and $21.1 million, respectively, of supplemental bonds issued to the BOEM (which is reflected in the $244.0 million in lease and/or area bonds discussed above). On June 30, 2015, we sold the East Bay field, and as a result, the $1.0 billion of supplemental financial assurance and/or bonding required by the BOEM in April 2015 was reduced by approximately $178 million.

In October 2015, we received information from the BOEM indicating that, we could receive additional demands of supplemental financial assurance for amounts in addition to the $1.0 billion initially sought by the BOEM in April 2015, primarily relating to certain properties that were no longer exempt from supplemental bonding as a result of co-lessees losing their exemptions. However, we believe that a substantial portion of the additional supplemental financial assurance and/or bonding that could be sought by the BOEM may relate to circumstances that could eventually be removed from our responsibility (in terms of providing added assurance or bonding), 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. We would expect 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.

Since we received the additional information from the BOEM in October 2015, we have had a series of discussions and exchanges of information with the BOEM on the long-term financial assurance plan, culminating most recently in our submittal of an updated version of the long-term financial assurance plan to the BOEM for approval on February 2, 2016. The long-term plan calls for a series of actions by us during various dates in 2016, including by June 1, 2016 and September 1, 2016, which actions are designed to address the supplemental financial assurance liabilities initially identified by the BOEM, as such liabilities are further modified by the BOEM based on information we provide and our performance under the plan. This long-term plan requires approval by the BOEM in order for us to proceed with addressing these supplemental financial assurance liabilities. While we believe that the long-term financial assurance plan is close to being approved by the BOEM, we can provide no assurance as to a certain date by which the long-term plan will be approved or that BOEM will not have further revisions to our proposal.

If our co-lessees and us are unable to agree on allocation of supplemental financial assurance and/or bonding amounts for such specified leases and present such agreed upon allocations to the BOEM for approval, the BOEM may direct supplemental financial assurance and/or bonding amounts for 100% of the lease interests to us, which would substantially increase the supplemental financial assurance and/or bonding

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 15 — Commitments and Contingencies  – (continued)

requirements. We expect that the BOEM will assess additional supplemental financial assurance and/or bonding requirements on us in such other letters that may be issued later if those items are not addressed in our plan.

Unrelated to the BOEM’s April 2015 directive, on September 22, 2015, the BOEM issued Draft Guidance relating to supplemental bonding procedures that will, among other things, eliminate the “waiver” exemption currently allowed by the BOEM with respect to supplemental bonding and, instead, broaden the self-insurance approach that would allow more operators on the OCS to seek self-insurance for a portion of their supplemental bond obligations, but only for an amount that is no more than 10% of such operators’ tangible net worth. In addition, the Draft Guidance would implement a phased-in period for establishing compliance with supplemental bonding obligations, whereby operators may seek payment of estimated costs of decommissioning obligations owed under a “tailored plan” that is approved by the BOEM and would require payment of the supplemental bonding amount in three approximately equal installments of one-third each, by no later than 120, 240 and 360 calendar days, respectively, from the date of BOEM approval of the tailored plan. Furthermore, with issuance of an Advanced Notice of Proposed Rulemaking in August 2014, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters.

While the Draft Guidance, once implemented by the BOEM, would allow an increased number of operators (relative to those operators under the existing Notice to Lessees (“NTL”) regarding supplemental financial assurance and bonding) to self-insure for their decommissioning liabilities that is no more than 10% of their tangible net worth, there is no assurance that the BOEM will allow us to utilize self-insurance programs and we currently do not plan for self-insurance under the long-term financial assurance plan that we submitted to the BOEM.

In addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the bureau, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The cost of compliance with our existing supplemental bonding requirements, including the directives issued by the BOEM in April 2015 and June 2015, any other future directives, or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding regulations 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 or letters of credit to support the issuance of such bonds or other surety. Such letters of credit would likely be issued under our Revolving Credit Facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations.

We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our Revolving Credit Facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require 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, 2015, our restricted cash primarily related to $30 million related to the First Lien Credit Agreement, $16 million in cash collateral associated with our bonding requirements, $3.3 million related to the Grand Isle Gathering System (“GIGS”) transaction and approximately $6 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field which will be transferred to the buyer of our interests in that field.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 15 — Commitments and Contingencies  – (continued)

We and our oil and natural 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 16 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (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, restricted cash, 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 11.0% Notes, 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, 6.875% Senior Notes and 3.0% Senior Convertible Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are considered Level 2 inputs within the fair value hierarchy. The carrying value of the Revolving Credit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 8 — 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.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 16 — Fair Value of Financial Instruments  – (continued)

During the three and six months ended December 31, 2015, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

       
  Level 1   Level 2
     As of
December 31,
2015
  As of
June 30,
2015
  As of
December 31,
2015
  As of
June 30,
2015
Assets:
                                   
Oil and natural gas derivatives   $     $     $ 62,557     $ 63,004  
Liabilities:
                                   
Oil and natural gas derivatives   $     $     $ 1,388     $ 40,896  
Restricted stock units     2,849       6,325              
Time-based performance units     541       1,978              
Total liabilities   $ 3,390     $ 8,303     $ 1,388     $ 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):

       
  December 31, 2015   June 30, 2015
     Carrying
Value
  Estimated
Fair Value
  Carrying
Value
  Estimated
Fair Value
Revolving credit facility   $ 150,000     $ 150,000     $ 150,000     $ 150,000  
11% Senior Secured Second Lien Notes due 2020     1,403,011       518,375       1,398,896       1,276,000  
8.25% Senior Notes due 2018     501,462       135,813       539,459       306,000  
6.875% Senior Notes due 2024     143,993       17,999       650,000       211,250  
3.0% Senior Convertible Notes due 2018     360,194       24,000       354,218       94,000  
7.5% Senior Notes due 2021     238,071       25,890       500,000       164,925  
7.75% Senior Notes due 2019     101,077       16,172       250,000       92,135  
9.25% Senior Notes due 2017     720,585       210,771       750,000       413,160  
     $ 3,618,393     $ 1,099,020     $ 4,592,573     $ 2,707,470  

The 11.0% Notes, the 8.25% Senior Notes, the 6.875% Senior Notes, and the 7.5% Senior Notes each contain an option to redeem up to 35% of the aggregate principal amount of the respective notes outstanding with the net cash proceeds of certain equity offerings. Such options are considered embedded derivatives and are classified as Level 3 financial instruments for which the estimated fair values at December 31, 2015 are not material.

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

   
  Three Months Ended December 31,
     2015   2014
Liabilities:
                 
Performance-based performance units
                 
Balance at beginning of period   $ 1     $ 841  
Vested            
Grants charged to general and administrative expense     841       (732 ) 
Balance at end of period   $ 842     $ 109  

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 17 — Prepayments and Accrued Liabilities

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

   
  December 31,
2015
  June 30,
2015
Prepaid expenses and other current assets
                 
Advances to joint interest partners   $ 4,232     $ 1,294  
Insurance     13,535       3,427  
Inventory     398       7,867  
Royalty deposit     2,871       3,137  
Other     12,957       8,573  
Total prepaid expenses and other current assets   $ 33,993     $ 24,298  
Accrued liabilities
                 
Advances from joint interest partners     2,695       3,060  
Employee benefits and payroll     7,850       18,927  
Interest payable     70,120       83,384  
Accrued hedge payable     126       1,399  
Undistributed oil and gas proceeds     20,002       19,776  
Severance taxes payable     675       843  
Other     16,379       27,917  
Total accrued liabilities   $ 117,847     $ 155,306  

Note 18 — Supplemental Guarantor Information

Our indirect, 100% wholly owned subsidiary, EGC, issued the 6.875% Senior Notes, the 7.5% Senior Notes, the 9.25% Senior Notes and the 7.75% Senior Notes, each of which were replaced with identical notes issued in registered offerings. These notes are jointly, severally, fully and unconditionally guaranteed by the Bermuda parent company and each of EGC’s existing and future material domestic subsidiaries other than EPL and its subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the senior note indentures. These customary circumstances include: when a guarantor is declared “unrestricted” for covenant purposes, when the requirements for legal defeasance or covenant defeasance or to discharge the indenture have been satisfied, when the guarantor is sold or sells all of its assets or the guarantor no longer guarantees any obligations under EGC’s Revolving Credit Facility. When securities that are guaranteed are issued in a registered offering, Rule 3-10 of Regulation S-X of the SEC generally requires the issuer and guarantors to file separate financial statements. We meet the conditions in Rule 3-10 to instead report information about the assets, liabilities, results of operations and cash flows of the parent, subsidiary issuer and subsidiary guarantors using an alternative approach, which is to include in a footnote to our financial statements, condensed consolidating financial information for the same periods as those presented in our financial statements.

The information is presented using the equity method of accounting for investments in subsidiaries. Transactions between entities are presented on a gross basis in the Bermuda parent company, EGC, guarantor subsidiaries, and non-guarantor subsidiaries columns with consolidating entries presented in the eliminations column. The principal consolidating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses. The following supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements and should be read in conjunction with our consolidated financial statements and notes thereto included in the 2015 Annual Report.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 18 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET
(Unaudited)

           
  December 31, 2015
     EXXI
Bermuda Parent
  EGC
Issuer
  Guarantor Subsidiaries   Non-Guarantor Subsidiaries   Reclassifications & Eliminations   Consolidated
     (In Thousands)
ASSETS
                                                     
Current Assets
                                                     
Cash and cash equivalents   $ 24,839     $ 297,749     $ 2,750     $ 552     $     $ 325,890  
Accounts receivable
                                                     
Oil and natural gas sales                 41,868       21,753       (3,441 )      60,180  
Joint interest billings           4,769       699       15,132             20,600  
Other           13,365       3,736       5,566             22,667  
Prepaid expenses and other current assets     725       26,037       3,712       3,519             33,993  
Restricted cash                 350       9,358             9,708  
Derivative financial instruments           61,169                         61,169  
Total Current Assets     25,564       403,089       53,115       55,880       (3,441 )      534,207  
Property and Equipment
                                                     
Oil and natural gas properties, net                 615,039       481,427             1,096,466  
Other property and equipment, net                 1,604       17,740             19,344  
Total Property and Equipment, net                 616,643       499,167             1,115,810  
Other Assets
                                                     
Derivative financial instruments                                    
Equity investments                       1,635,236       (1,635,236 )       
Intercompany receivables     129,084       1,687,581             49,763       (1,866,428 )       
Restricted cash           16,016             30,008             46,024  
Other assets and debt issuance costs, net     176,093       377,308       832       12,992       (499,029 )      68,196  
Total Other Assets     305,177       2,080,905       832       1,727,999       (4,000,693 )      114,220  
Total Assets   $ 330,741     $ 2,483,994     $ 670,590     $ 2,283,046     $ (4,004,134 )    $ 1,764,237  
LIABILITIES
                                                     
Current Liabilities
                                                     
Accounts payable   $     $ 41,091     $ 52,141     $ 70,969     $ (3,514 )    $ 160,687  
Accrued liabilities     1,014       57,094       14,592       160,682       (115,535 )      117,847  
Asset retirement obligations                 14,059       29,077             43,136  
Current maturities of long-term debt                       873             873  
Total Current Liabilities     1,014       98,185       80,792       261,601       (119,049 )      322,543  
Long-term debt, less current maturities     360,194       2,606,737             900,577       (245,000 )      3,622,508  
Deferred income taxes     26,696                         (26,696 )       
Intercompany notes payable                       496,000       (496,000 )       
Asset retirement obligations           50       259,971       168,402       (7,493 )      420,930  
Accumulated losses in excess of equity investments     2,559,901       2,064,289                   (4,624,190 )       
Intercompany payables                 1,724,294       13,502       (1,737,796 )       
Other liabilities           5,332       2,668       7,319             15,319  
Total Liabilities     2,947,805       4,774,593       2,067,725       1,847,401       (7,256,224 )      4,381,300  
Stockholders’ Equity (Deficit)
                                                     
Preferred stock
                                                     
7.25% Convertible perpetual preferred stock                                    
5.625% Convertible perpetual preferred
stock
    1                               1  
Common stock     476       1             12       (13 )      476  
Additional paid-in capital     1,845,212       2,236,216       114,825       7,361,860       (9,712,901 )      1,845,212  
Accumulated deficit     (4,462,753 )      (4,526,816 )      (1,511,960 )      (6,926,227 )      12,965,004       (4,462,752 ) 
Total Stockholders’ Equity (Deficit)     (2,617,064 )      (2,290,599 )      (1,397,135 )      435,645       3,252,090       (2,617,063 ) 
Total Liabilities and Stockholders’ Equity (Deficit)   $ 330,741     $ 2,483,994     $ 670,590     $ 2,283,046     $ (4,004,134 )    $ 1,764,237  

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 18 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET

           
  June 30, 2015
     EXXI
Bermuda
Parent
  EGC
Issuer
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Reclassifications & Eliminations   Consolidated
     (In Thousands)
ASSETS
                                                     
Current Assets
                                                     
Cash and cash equivalents   $ 37,053     $ 719,609     $     $ 186     $     $ 756,848  
Accounts receivable
                                                     
Oil and natural gas sales                 68,514       36,963       (5,234 )      100,243  
Joint interest billings           2,015             10,418             12,433  
Other     622       17,819       140       24,932             43,513  
Prepaid expenses and other current assets     280       13,211             11,469       (662 )      24,298  
Restricted cash                          9,359             9,359  
Derivative financial instruments           21,341             888             22,229  
Total Current Assets     37,955       773,995       68,654       94,215       (5,896 )      968,923  
Property and Equipment
                                                     
Oil and natural gas properties, net                 2,112,635       1,408,585       49,539       3,570,759  
Other property and equipment, net                       21,820             21,820  
Total Property and Equipment, net                 2,112,635       1,430,405       49,539       3,592,579  
Other Assets
                                                     
Derivative financial instruments           3,898                         3,898  
Equity investments           428,368             3,591,757       (4,009,290 )      10,835  
Intercompany receivables     122,039       1,626,679             93,844       (1,842,562 )       
Restricted cash           31,000             1,667             32,667  
Other assets and debt issuance costs, net     176,861       464,617             8,729       (568,280 )      81,927  
Total Other Assets     298,900       2,554,562             3,695,997       (6,420,132 )      129,327  
Total Assets   $ 336,855     $ 3,328,557     $ 2,181,289     $ 5,220,617     $ (6,376,489 )    $ 4,690,829  
LIABILITIES
                                                     
Current Liabilities
                                                     
Accounts payable   $     $ 39,378     $ 41,027     $ 81,052     $ (5,118 )    $ 156,339  
Accrued liabilities     976       69,566       16,060       166,851       (98,147 )      155,306  
Deferred income taxes     24,174                         (24,174 )       
Asset retirement obligations                 624       32,662             33,286  
Derivative financial instruments           1,603             1,058             2,661  
Current maturities of long-term debt           7,283             4,112             11,395  
Total Current Liabilities     25,150       117,830       57,711       285,735       (127,439 )      358,987  
Long-term debt, less current maturities     354,218       3,548,896             938,923       (245,000 )      4,597,037  
Intercompany notes payable                       565,105       (565,105 )       
Asset retirement obligations           50       251,444       209,431       (7,126 )      453,799  
Derivative financial instruments           1,358                         1,358  
Accumulated losses in excess of equity investments     686,209                         (686,209 )       
Intercompany payables                 1,721,211             (1,721,211 )       
Other liabilities           5,332             3,038             8,370  
Total Liabilities     1,065,577       3,673,466       2,030,366       2,002,232       (3,352,090 )      5,419,551  
Stockholders’ Equity (Deficit)
                                                     
Preferred stock
                                                     
7.25% Convertible perpetual preferred stock                                    
5.625% Convertible perpetual preferred
stock
    1                               1  
Common stock     472       1             12       (13 )      472  
Additional paid-in capital     1,843,918       2,252,142       78,599       7,377,784       (9,708,525 )      1,843,918  
Accumulated earnings (deficit)     (2,573,113 )      (2,597,052 )      72,324       (4,159,411 )      6,684,139       (2,573,113 ) 
Total Stockholders’ Equity (Deficit)     (728,722 )      (344,909 )      150,923       3,218,385       (3,024,399 )      (728,722 ) 
Total Liabilities and Stockholders’ Equity (Deficit)   $ 336,855     $ 3,328,557     $ 2,181,289     $ 5,220,617     $ (6,376,489 )    $ 4,690,829  

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 18 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)

           
  For the Three Months Ended December 31, 2015
     EXXI Bermuda Parent   EGC
Issuer
  Guarantor Subsidiaries   Non-Guarantor Subsidiaries   Reclassifications & Eliminations   Consolidated
     (In thousands)
Revenues
                                                     
Oil sales   $     $     $ 71,942     $ 75,508     $ (7,752 )    $ 139,698  
Natural gas sales                 8,359       8,256             16,615  
Gain on derivative financial instruments           27,396             906             28,302  
Total Revenues           27,396       80,301       84,670       (7,752 )      184,615  
Costs and Expenses
                                                     
Lease operating           635       43,972       51,505       (7,754 )      88,358  
Production taxes           2       303       4             309  
Gathering and transportation                 16,852             (74 )      16,778  
Depreciation, depletion and amortization                 61,613       63,157       (3,203 )      121,567  
Accretion of asset retirement obligations                 9,627       6,503       (186 )      15,944  
Impairment of oil and natural gas properties                 918,295       504,781       2,716       1,425,792  
General and administrative expense     3,201       4,808       10,823       10,183             29,015  
Total Costs and Expenses     3,201       5,445       1,061,485       636,133       (8,501 )      1,697,763  
Operating Income (Loss)     (3,201 )      21,951       (981,184 )      (551,463 )      749       (1,513,148 ) 
Other Income (Expense)
                                                     
Income (loss) from equity method investees     (1,302,666 )      (1,525,228 )            (1,300,850 )      4,128,744        
Other income (expense), net     4,230       8,680       1       6,880       (17,237 )      2,554  
Gain on early extinguishment of debt           269,027             21,269             290,296  
Interest expense     (6,426 )      (75,281 )            (32,516 )      23,989       (90,234 ) 
Total Other Income (Expense), net     (1,304,862 )      (1,322,802 )      1       (1,305,217 )      4,135,496       202,616  
Income (Loss) Before Income Taxes     (1,308,063 )      (1,300,851 )      (981,183 )      (1,856,680 )      4,136,245       (1,310,532 ) 
Income Tax Expense     2,521                   51       (2,521 )      51  
Net Income (Loss)     (1,310,584 )      (1,300,851 )      (981,183 )      (1,856,731 )      4,138,766       (1,310,583 ) 
Preferred Stock Dividends     2,810                               2,810  
Net Income (Loss) Attributable to Common Stockholders   $ (1,313,394 )    $ (1,300,851 )    $ (981,183 )    $ (1,856,731 )    $ 4,138,766     $ (1,313,393 ) 

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 18 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)

           
  For the Three Months Ended December 31, 2014
     EXXI Bermuda Parent   EGC
Issuer
  Guarantor Subsidiaries   Non-Guarantor Subsidiaries   Reclassifications & Eliminations   Consolidated
     (In thousands)
Revenues
                                                     
Oil sales   $     $     $ 158,883     $ 120,825     $     $ 279,708  
Natural gas sales                 19,253       12,548             31,801  
Gain on derivative financial instruments           169,226             22,236             191,462  
Total Revenues           169,226       178,136       155,609             502,971  
Costs and Expenses
                                                     
Lease operating           86       62,828       56,452             119,366  
Production taxes           2       957       1,304             2,263  
Gathering and transportation                 4,771                   4,771  
Depreciation, depletion and amortization                 98,461       89,361       (12,667 )      175,155  
Accretion of asset retirement obligations                 6,700       6,098             12,798  
Impairments                       482,598       (153,305 )      329,293  
General and administrative expense     2,348       1,939       25,655       (2,197 )            27,745  
Total Costs and Expenses     2,348       2,027       199,372       633,616       (165,972 )      671,391  
Operating Income (Loss)     (2,348 )      167,199       (21,236 )      (478,007 )      165,972       (168,420 ) 
Other Income (Expense)
                                                     
Loss from equity method investees     (278,486 )      (357,623 )            (361,702 )      996,536       (1,275 ) 
Other income (expense), net     5,144       485             3,611       (8,249 )      991  
Interest expense     (6,188 )      (48,273 )      (1,419 )      (29,324 )      18,303       (66,901 ) 
Total Other Income (Expense), net     (279,530 )      (405,411 )      (1,419 )      (387,415 )      1,006,590       (67,185 ) 
Income (Loss) Before Income Taxes     (281,878 )      (238,212 )      (22,655 )      (865,422 )      1,172,562       (235,605 ) 
Income Tax Expense     1,528       32,086             6,744             40,358  
Net Income (Loss)     (283,406 )      (270,298 )      (22,655 )      (872,166 )      1,172,562       (275,963 ) 
Preferred Stock Dividends     2,870                               2,870  
Net Income (Loss) Attributable to Common Stockholders   $ (286,276 )    $ (270,298 )    $ (22,655 )    $ (872,166 )    $ 1,172,562     $ (278,833 ) 

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 18 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)

           
  For the Six Months Ended December 31, 2015
     EXXI Bermuda Parent   EGC
Issuer
  Guarantor Subsidiaries   Non-Guarantor Subsidiaries   Reclassifications & Eliminations   Consolidated
     (In thousands)
Revenues
                                                     
Crude oil sales   $     $     $ 164,260     $ 170,610     $ (16,264 )    $ 318,606  
Natural gas sales                 19,226       20,874             40,100  
Gain on derivative financial instruments           79,957       91       3,684             83,732  
Total Revenues           79,957       183,577       195,168       (16,264 )      442,438  
Costs and Expenses
                                                     
Lease operating           2,551       97,268       99,424       (16,263 )      182,980  
Production taxes           11       710       345             1,066  
Gathering and transportation                 31,904             (148 )      31,756  
Depreciation, depletion and amortization                 127,237       121,623       (3,269 )      245,591  
Accretion of asset retirement obligations                 17,670       13,425       (367 )      30,728  
Impairment of oil and natural gas properties                 1,464,681       812,942       52,838       2,330,461  
General and administrative expense     6,275       8,982       18,645       17,302             51,204  
Total Costs and Expenses     6,275       11,544       1,758,115       1,065,061       32,791       2,873,786  
Operating Income (Loss)     (6,275 )      68,413       (1,574,538 )      (869,893 )      (49,055 )      (2,431,348 ) 
Other Income (Expense)
                                                     
Loss from equity method investees     (1,871,169 )      (2,512,963 )      (9,687 )      (1,864,052 )      6,247,125       (10,746 ) 
Other income (expense), net     8,780       17,561       4       11,380       (34,677 )      3,048  
Gain on early extinguishment of debt           727,305             21,269             748,574  
Interest expense     (12,791 )      (163,309 )      (63 )      (65,469 )      48,180       (193,452 ) 
Total Other Income (Expense), net     (1,875,180 )      (1,931,406 )      (9,746 )      (1,896,872 )      6,260,628       547,424  
Income (Loss) Before Income Taxes     (1,881,455 )      (1,862,993 )      (1,584,284 )      (2,766,765 )      6,211,573       (1,883,924 ) 
Income Tax Expense     2,521                   51       (2,521 )      51  
Net Income (Loss)     (1,883,976 )      (1,862,993 )      (1,584,284 )      (2,766,816 )      6,214,094       (1,883,975 ) 
Preferred Stock Dividends     5,664                               5,664  
Net Income (Loss) Attributable to Common Stockholders   $ (1,889,640 )    $ (1,862,993 )    $ (1,584,284 )    $ (2,766,816 )    $ 6,214,094     $ (1,889,639 ) 

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 18 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)

           
  For the Six Months Ended December 31, 2014
     EXXI Bermuda Parent   EGC
Issuer
  Guarantor Subsidiaries   Non-Guarantor Subsidiaries   Reclassifications & Eliminations   Consolidated
     (In thousands)
Revenues
                                                     
Oil sales   $     $     $ 370,723     $ 279,140     $     $ 649,863  
Natural gas sales                 39,860       26,502             66,362  
Gain on derivative financial instruments           204,094             44,093                248,187  
Total Revenues           204,094       410,583       349,735             964,412  
Costs and Expenses
                                                     
Lease operating                 148,574       113,377             261,951  
Production taxes           16       2,078       3,262             5,356  
Gathering and transportation                 13,959                   13,959  
Depreciation, depletion and amortization                 189,525       163,844       (19,074 )      334,295  
Accretion of asset retirement obligations                 13,338       12,279             25,617  
Impairments                       482,598       (153,305 )      329,293  
General and administrative expense     3,495       3,710       30,265       16,699             54,169  
Total Costs and Expenses     3,495       3,726       397,739       792,059       (172,379 )      1,024,640  
Operating Income (Loss)     (3,495 )      200,368       12,844       (442,324 )      172,379       (60,228 ) 
Other Income (Expense)
                                                     
Loss from equity method investees     (247,647 )      (295,722 )            (358,659 )      901,712       (316 ) 
Other income (expense), net     10,316       969             8,960       (18,303 )      1,942  
Interest expense     (12,321 )      (95,926 )      (2,914 )      (40,306 )      18,303       (133,164 ) 
Total Other Income (Expense), net     (249,652 )      (390,679 )      (2,914 )      (390,005 )      901,712       (131,538 ) 
Income (Loss) Before Income Taxes     (253,147 )      (190,311 )      9,930       (832,329 )      1,074,091       (191,766 ) 
Income Tax Expense     3,069       44,387             9,551             57,007  
Net Income (Loss)     (256,216 )      (234,698 )      9,930       (841,880 )      1,074,091       (248,773 ) 
Preferred Stock Dividends     5,742                               5,742  
Net Income (Loss) Attributable to Common Stockholders   $ (261,958 )    $ (234,698 )    $ 9,930     $ (841,880 )    $ 1,074,091     $ (254,515 ) 

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 18 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Unaudited)

           
  For the Six Months Ended December 31, 2015
     EXXI Bermuda Parent   EGC Issuer   Guarantor Subsidiaries   Non-Guarantor Subsidiaries   Reclassifications & Eliminations   Consolidated
     (In Thousands)
Cash Flows From Operating Activities
                                                     
Net loss   $ (1,883,976 )    $ (1,862,993 )    $ (1,584,284 )    $ (2,766,816 )    $ 6,214,094     $ (1,883,975 ) 
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
                                                     
Depreciation, depletion and amortization                 127,237       121,623       (3,269 )      245,591  
Deferred income taxes     2,521                         (2,521 )       
Impairment of oil and natural gas properties                 1,464,681       812,942       52,838       2,330,461  
Gain on early extinguishment of debt           (727,305 )            (21,269 )            (748,574 ) 
Change in fair value of derivative financial instruments           (40,589 )            (1,573 )            (42,162 ) 
Accretion of asset retirement obligations                 17,670       13,425       (367 )      30,728  
Loss (income) from equity method
investees
    1,871,169       2,512,963       9,687       1,864,052       (6,247,125 )      10,746  
Amortization of debt issuance costs and
other
    6,741       10,767       63       (6,306 )      (148 )      11,117  
Deferred rent                       4,577             4,577  
Stock-based compensation     987                               987  
Changes in operating assets and liabilities                                                   
Accounts receivable     622       4,751       33,447       32,078       (25 )      70,873  
Prepaid expenses and other assets     (445 )      (15,625 )      2,006       3,063             (11,001 ) 
Settlement of asset retirement obligations                 (10,486 )      (43,233 )            (53,719 ) 
Accounts payable and accrued liabilities     (4,472 )      (79,549 )      14,202       54,239       (39,993 )      (55,573 ) 
Net Cash Provided by (Used in) Operating Activities     (6,853 )      (197,580 )      74,223       66,802       (26,516 )      (89,924 ) 
Cash Flows from Investing Activities
                                                     
Acquisitions, net of cash                 (2,797 )                  (2,797 ) 
Capital expenditures           (44 )      (52,041 )      (20,702 )      (2,997 )      (75,784 ) 
Insurance payments received                 4,379                   4,379  
Intercompany investment           (26,451 )                  26,451        
Transfers from (to) restricted cash           14,984             (28,339 )            (13,355 ) 
Proceeds from the sale of properties           15       4,173       435             4,623  
Other                       62             62  
Net Cash Used in Investing Activities           (11,496 )      (46,286 )      (48,544 )      23,454       (82,872 ) 
Cash Flows from Financing Activities
                                                     
Proceeds from the issuance of common and preferred stock, net of offering costs     312                               312  
Dividends to shareholders – preferred     (5,673 )                              (5,673 ) 
Proceeds from long-term debt           1,121                         1,121  
Payments on long-term debt           (211,382 )            (13,622 )            (225,004 ) 
Payment of debt assumed in acquisition                 (25,187 )                  (25,187 ) 
Fees related to debt extinguishment           (2,080 )                        (2,080 ) 
Debt issuance costs           (443 )            (189 )            (632 ) 
Other                       (4,081 )      3,062       (1,019 ) 
Net Cash Used in Financing Activities     (5,361 )      (212,784 )      (25,187 )      (17,892 )      3,062       (258,162 ) 
Net Decrease in Cash and Cash Equivalents     (12,214 )      (421,860 )      2,750       366             (430,958 ) 
Cash and Cash Equivalents, beginning of period     37,053       719,609             186             756,848  
Cash and Cash Equivalents, end of period   $ 24,839     $ 297,749     $ 2,750     $ 552     $     $ 325,890  

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 18 — Supplemental Guarantor Information  – (continued)

ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Unaudited)

           
  For the Six Months Ended December 31, 2014
     EXXI Bermuda Parent   EGC
Issuer
  Guarantor Subsidiaries   Non-Guarantor Subsidiaries   Reclassifications & Eliminations   Consolidated
     (In Thousands)
Cash Flows From Operating Activities
                                                     
Net income (loss)   $ (256,216 )    $ (234,698 )    $ 9,930     $ (841,880 )    $ 1,074,091     $ (248,773 ) 
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
                                                     
Depreciation, depletion and amortization                 189,525       163,844       (19,074 )      334,295  
Goodwill impairment                       482,598       (153,305 )      329,293  
Deferred income tax expense     2,508       45,562             8,377             56,447  
Change in fair value of derivative financial instruments           (161,075 )            (14,656 )            (175,731 ) 
Accretion of asset retirement obligations                 13,338       12,279             25,617  
Income from equity method investees     247,647       295,722             358,659       (901,712 )      316  
Amortization of debt issuance costs and other     6,274       4,421             (5,080 )            5,615  
Stock-based compensation     2,632                               2,632  
Changes in operating assets and liabilities
                                                     
Accounts receivable     10       (20,454 )      52,556       1,707             33,819  
Prepaid expenses and other assets     (470 )      5,259       137       17,557             22,483  
Settlement of asset retirement obligations                 (53,960 )                  (53,960 ) 
Accounts payable and accrued liabilities     (9,821 )      (188,469 )      (18,207 )      (105,007 )      150,759       (170,745 ) 
Net Cash Provided by (Used in) Operating Activities     (7,436 )      (253,732 )      193,319       78,398       150,759       161,308  
Cash Flows from Investing Activities
                                                     
Acquisitions, net of cash                 (287 )                  (287 ) 
Capital expenditures                 (200,304 )      (248,810 )            (449,114 ) 
Change in equity method investments                       12,642             12,642  
Intercompany investment                       153,000       (153,000 )       
Transfers from restricted cash                 325                   325  
Proceeds from the sale of properties                 6,947                   6,947  
Other                       95             95  
Net Cash Used in Investing Activities                 (193,319 )      (83,073 )      (153,000 )      (429,392 ) 
Cash Flows from Financing Activities
                                                     
Proceeds from the issuance of common and preferred stock, net of offering costs     2,059                               2,059  
Dividends to shareholders – common     (22,548 )                              (22,548 ) 
Dividends to shareholders – preferred     (5,744 )                              (5,744 ) 
Proceeds from long-term debt           1,011,948                         1,011,948  
Payments on long-term debt           (759,637 )            (214 )            (759,851 ) 
Debt issuance costs           (2,302 )                        (2,302 ) 
Other                                    
Net Cash Provided by (Used in) Financing Activities     (26,233 )      250,009             (214 )            223,562  
Net Decrease in Cash and Cash Equivalents     (33,669 )      (3,723 )            (4,889 )      (2,241 )      (44,522 ) 
Cash and Cash Equivalents, beginning of period     135,703       3,723             6,380             145,806  
Cash and Cash Equivalents, end of period   $ 102,034     $     $     $ 1,491     $ (2,241 )    $ 101,284  

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statements we make in this quarterly report on Form 10-Q (the “Quarterly Report”) which express a belief, expectation or intention, as well as those that are not historical fact, may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Our forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the headings “Cautionary Statement Concerning Forward-Looking Statements” and “Item 1A. Risk Factors” included in our 2015 Annual Report and elsewhere in this Quarterly Report.

Overview

Energy XXI Ltd and its wholly owned subsidiaries (“Energy XXI,” “us,” “we,” “our,” or “the Company”) is an independent oil and natural gas exploration and production company. With our principal operating subsidiary headquartered in Houston, Texas, we are engaged in the acquisition, development, operation and exploration of oil and natural gas properties onshore in Louisiana and on the Gulf of Mexico Shelf (“GoM Shelf”). Based on production volume, we are the largest publicly traded independent operator on the GoM Shelf. We intend to strengthen our position in a safe environment with a focus on delivering value for our shareholders.

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

At June 30, 2015, our total proved reserves were 183.5 MMBOE of which 75% were oil and 68% were classified as proved developed. We operated or had an interest in 567 gross producing wells on 388,199 net developed acres, including interests in 52 producing fields. We believe operating our assets is a key to our success and approximately 97% 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 which has continued into fiscal year 2016. In response to that decline, we initiated a series of financial and operational activities highlighted below.

Our fiscal year 2016 capital budget was reduced to a current planned amount of $130 to $150 million, as compared to actual capital expenditures in fiscal year 2015 (excluding acquisition activity) of approximately $649 million. Our fiscal year 2016 budget is primarily focused on: (i) recompletion opportunities and lower risk development drilling opportunities in fields where we have had previous success and (ii) eliminating capital commitments on exploration and other activities that do not provide incremental production.
We have reduced field level operating costs, bringing lease operating costs per barrel down by 34% from first quarter of fiscal year 2015, and we are continuing to focus on operational and cost efficiencies.
We have suspended dividends on our common stock for the foreseeable future.
On March 12, 2015, we closed our private placement of $1.45 billion in aggregate principal amount of the 11.0% Notes for net proceeds of $1.35 billion, after deducting the initial purchasers’ discount and direct offering costs paid by us. Of the net proceeds, $836 million was used to reduce our outstanding borrowings under our Revolving Credit Facility to $150 million, with the remaining amount available for general corporate purposes, including funding a portion of our capital expenditure program for fiscal year 2015 and for fiscal year 2016 as well as funding a portion of our bond repurchases in fiscal 2016.
In connection with the issuance of the 11.0% Notes, we proactively amended our Revolving Credit Facility, to, among other things, reduce the total borrowing base availability to $500 million and make certain modifications to the existing financial covenants. On November 30, 2015, our lenders

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reaffirmed the total borrowing base of our revolving credit facility at $500 million and temporarily relaxed the requirements of certain financial covenants. Please read “—Liquidity and Capital Resources — Our Indebtedness and Available Credit — Revolving Credit Facility” below for additional information.
On June 30, 2015, we sold the Grand Isle Gathering System (the “GIGS”) for $245 million in cash, plus the assumption of an estimated $12.5 million asset retirement obligation associated with the decommissioning costs of the GIGS. In connection with the closing of the sale of the GIGS, we entered into a triple-net lease with Grand Isle Corridor pursuant to which we will continue to operate the GIGS.
In addition, on June 30, 2015, we sold our interest in the East Bay field for cash consideration of $21 million, plus the assumption by the buyer of asset retirement obligations totaling approximately $55.1 million. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65/Bbl) on these assets for a period not to exceed five 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.
During January 2015, we monetized our existing calendar 2015 ICE Brent three-way collars and Argus-LLS put spreads for total net proceeds of approximately $73.1 million. Additionally, we repositioned our calendar 2015 hedging portfolio by putting on Argus-LLS three-way collars, and we entered into NYMEX WTI costless collars to hedge a portion of our calendar 2016 production at the then current commodity prices, which provides us some price protection against further decline in oil prices. Currently, we have some price protection on approximately 14,000 barrels of crude oil per day representing approximately 40% of our estimated crude oil production volumes in calendar 2016 under our hedging portfolio. Please see Note 8 – Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report for a detailed discussion of our hedging program.
From July 1, 2015 through December 31, 2015, we repurchased approximately $976.0 million of our unsecured notes in open market transactions at a total cost of approximately $213.1 million, reducing our total indebtedness to approximately $3,623.4 million as of December 31, 2015. We recorded a gain on the repurchases totalling approximately $748.6 million, net of associated debt issuance costs and certain other expenses. Subsequent to December 31, 2015, we repurchased approximately $737.7 million of our unsecured notes in open market transactions at a total price of approximately $19.2 million, including $16.4 million of accrued interest, reducing our total indebtedness to approximately $2,874.6 million as of February 15, 2016.

Due to the uncertainty regarding future commodity prices, we plan to manage our operating activities and financial liquidity carefully. We do not expect production increases from our fiscal year 2016 capital program to entirely offset production declines, resulting in slight decreases to our production. We plan to continuously evaluate our level of operating activity in light of both actual commodity prices and changes we are able to make to our costs of operations and make further adjustments to our capital spending program as appropriate. In addition, in light of current commodity prices and our leverage position, in February 2016, we engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise management and the Board regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. On February 16, 2016, the Company elected to enter into the 30-day grace period under the terms of the indenture governing EPL’s 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company will work with its debt holders regarding its ongoing effort to develop and implement a comprehensive plan to restructure its balance sheet, as discussed above. For additional detail, see “— Liquidity — Overview.” We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. If we are unable to improve our liquidity position, refinance or restructure our debt obligations or are unsuccessful in implementing such strategic alternatives, we may seek

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bankruptcy protection to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements.

Known Trends and Uncertainties

Commodity Price Volatility and Impact on our Results of Operations, Compliance with Debt Instruments and Liquidity.  Prices for oil and natural gas historically have been volatile and are expected to continue to be volatile. Oil and natural gas prices declined significantly during fiscal year 2015 and the decline has continued into fiscal year 2016. The posted price per barrel for West Texas intermediate light sweet crude oil, or WTI, for the period from October 1, 2014 to December 31, 2015 ranged from a high of $91.01 to a low of $34.73, a decrease of 61.8%, and the NYMEX natural gas price per MMBtu for the period October 1, 2014 to December 31, 2015 ranged from a high of $4.49 to a low of $1.76, a decrease of 60.8%. As of December 31, 2015, the spot market price for WTI was $37.04. Oil prices have continued to decline in 2016, with the price of WTI crude oil per barrel dropping below $27.00 in January 2016 for the first time in twelve years. The recent declines in oil and natural gas prices have adversely affected our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce.

As of December 31, 2015, we were in compliance with our financial covenants under our Revolving Credit Facility, however, based on current market conditions and depressed commodity prices, if we are unable to execute on one of the strategic alternatives discussed below and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio covenant under our Revolving Credit Facility for the quarter ending March 31, 2016. There is no assurance that we will be able to resolve such non-compliance with our lenders, which may result in a default under our Revolving Credit Facility. In addition, as described in greater detail under “— Liquidity and Capital Resources — Overview,” our ability to access available borrowing capacity under our Revolving Credit Facility will be limited as a result of other provisions of the Revolving Credit Facility or a reduction in our borrowing base at our next redetermination in the spring of 2016. If we experience sustained periods of low prices for oil and natural gas, it will have a further material adverse effect on our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

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, assuming no other changes in our development plans. At December 31, 2015, our total proved reserves were 107.9 MMBOE. The unweighted arithmetic average first-day-of-the-month prices used to determine our reserves as of June 30, 2015 were $73.79 per barrel of oil, $29.54 per barrel for NGLs and $3.08 per MMBtu for natural gas, which is significantly higher than current forward strip prices. At NYMEX forward strip pricing as of January 29, 2016, we estimate that our total proved reserve equivalent volumes as of December 31, 2015 would have been approximately 3.1% higher compared to the results obtained using SEC pricing. Our estimated reserves as of June 30, 2015 may be further adjusted as warranted based on any changes to our long range plan, expected capital availability and drilling cost environment. The Company’s proved reserves declined significantly compared to prior year and may decline in future years. Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $336.5 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization.

Ceiling Test Write-down.  During the six months ended December 31, 2015, we recognized write-downs of our oil and natural gas properties totaling $2,330.5 million. The write-downs did not impact our cash flows from operating activities but resulted in our net loss for the period and increased our stockholders’ deficit. Further ceiling test write-downs will be required if oil and natural gas prices remain low or decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or the net

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capitalized cost of proved oil and natural gas properties otherwise exceeds the present value of estimated future net cash flows. 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 months ending January 31, 2016, we presently expect to incur further impairment of $200 million to $400 million in the third fiscal quarter of 2016. If the current low commodity price environment or downward trend in oil and natural gas prices continues, we will incur further impairment to our full cost pool in fiscal 2016 and beyond 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.

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

BOEM Supplemental Financial Assurance and/or Bonding Requirements.  As of December 31, 2015, we had $225 million in letters of credit to third parties relating to assets in the Gulf of Mexico and $405.7 million of performance bonds outstanding. As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (OCS), approximately $244.0 million of our performance bonds are lease and/or area bonds issued to the BOEM (including $65.4 million associated with our August 2015 acquisition of the remaining equity interests in M21K) that the BOEM has access to and assure our commitment to comply with the terms and conditions of those leases. We also maintain approximately $161.7 million in performance bonds issued to predecessor third party assignors rather than to the BOEM, 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 waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015 and December 2015, we reached agreements with the BOEM with respect to which we provided $150.0 million and $21.1 million, respectively, of supplemental bonds issued to the BOEM (which is reflected in the $244.0 million in lease and/or area bonds discussed above). On June 30, 2015, we sold the East Bay field, and as a result, the $1.0 billion of supplemental financial assurance and/or bonding required by the BOEM in April 2015 was reduced by approximately $178 million.

In October 2015, we received information from the BOEM indicating that we could receive additional demands of supplemental financial assurance for amounts in addition to the $1.0 billion initially sought by the BOEM in April 2015, primarily relating to certain properties that were no longer exempt from supplemental bonding as a result of co-lessees losing their exemptions. However, we believe that a substantial portion of the additional supplemental financial assurance and/or bonding that could be sought by the BOEM may relate to circumstances that could eventually be removed from our responsibility (in terms of providing added assurance or bonding), 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. We would expect 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 but we can provide no assurance that such cooperation by these co-lessees will occur.

Since we received the additional information from BOEM in October 2015, we have had a series of discussions and exchanges of information with the BOEM on the long-term financial assurance plan, culminating most recently in our submittal of an updated version of the long-term financial assurance plan to the BOEM for approval on February 2, 2016. The long-term plan calls for a series of actions by us during various dates in 2016, including by June 1, 2016 and September 1, 2016, which actions are designed to address the supplemental financial assurance liabilities initially identified by the BOEM, as such liabilities are further modified by the BOEM based on information we provide and our performance under the plan. This long-term plan requires approval by the BOEM in order for us to proceed with addressing these supplemental financial assurance liabilities. While we believe that the long-term financial assurance plan is close to being

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approved by the BOEM, we can provide no assurance as to a certain date by which the long-term plan will be approved or that BOEM will not have further revisions to our proposal.

If our co-lessees and us are unable to agree on allocation of supplemental financial assurance and/or bonding amounts for such specified leases and present such agreed upon allocations to the BOEM for approval, the BOEM may direct supplemental financial assurance and/or bonding amounts for 100% of the lease interests to us, which would substantially increase the supplemental financial assurance and/or bonding requirements. We expect that the BOEM will assess additional supplemental financial assurance and/or bonding requirements on us in such other letters that may be issued later if those items are not addressed in our plan.

Unrelated to the BOEM’s April 2015 directive, on September 22, 2015, the BOEM issued Draft Guidance relating to supplemental bonding procedures that will, among other things, eliminate the “waiver” exemption currently allowed by BOEM with respect to supplemental bonding and, instead, broaden the self-insurance approach that would allow more operators on the OCS to seek self-insurance for a portion of their supplemental bond obligations, but only for an amount that is no more than 10% of such operators’ tangible net worth. In addition, the Draft Guidance would implement a phased-in period for establishing compliance with supplemental bonding obligations, whereby operators may seek payment of estimated costs of decommissioning obligations owed under a “tailored plan” that is approved by the BOEM and would require payment of the supplemental bonding amount in three approximately equal installments of one-third each, by no later than 120, 240 and 360 calendar days, respectively, from the date of BOEM approval of the tailored plan. Furthermore, with issuance of an Advanced Notice of Proposed Rulemaking in August 2014, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters.

While the Draft Guidance, once implemented by the BOEM, would allow an increased number of operators (relative to those operators under the existing NTL regarding supplemental financial assurance and bonding) to self-insure for their decommissioning liabilities that is no more than 10% of their tangible net worth, there is no assurance that the BOEM will allow us to utilize self-insurance programs and we currently do not plan for self-insurance under the long-term financial assurance plan that we submitted to the BOEM.

In addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the bureau, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The cost of compliance with our existing supplemental bonding requirements, including the directives issued by the BOEM in April 2015 and June 2015, any other future directives, or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding regulations 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 or letters of credit to support the issuance of such bonds or other surety. Such letters of credit would likely be issued under our Revolving Credit Facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations.

We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our Revolving Credit Facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties, and one or more or such actions could have a material adverse 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 Bureau of Safety and Environmental Enforcement (“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.

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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.

Operational Information

         
  Quarter Ended
Operating Highlights   December 31,
2015
  September 30,
2015
  June 30,
2015
  March 31,
2015
  December 31,
2014
     (In thousands, except per unit amounts)
Operating revenues
                                            
Oil sales   $ 139,698     $ 178,908     $ 225,263     $ 177,605     $ 279,708  
Natural gas sales     16,615       23,485       23,908       27,012       31,801  
Gain (loss) on derivative financial instruments     28,302       55,430       (29,711 )      16,963       191,462  
Total revenues     184,615       257,823       219,460       221,580       502,971  
Percentage of operating revenues from oil prior to gain (loss) on derivative financial instruments     89 %      88 %      90 %      87 %      90 % 
Operating expenses
                                            
Lease operating expense
                                            
Insurance expense     10,042       11,335       8,963       8,828       11,233  
Workover and maintenance     6,656       22,028       12,243       10,773       13,130  
Direct lease operating expense     71,660       61,259       72,268       88,509       95,003  
Total lease operating expense     88,358       94,622       93,474       108,110       119,366  
Production taxes     309       757       1,492       1,537       2,263  
Gathering and transportation     16,778       14,978       3,459       3,726       4,771  
Depreciation, depletion and amortization     121,567       124,024       183,279       187,947       175,155  
Accretion of asset retirement obligations     15,944       14,784       12,358       12,106       12,798  
Impairment of oil and natural gas properties     1,425,792       904,669       1,852,268       569,616        
Goodwill impairment                             329,293  
General and administrative     29,015       22,189       25,210       37,121       27,745  
Total operating expenses     1,697,763       1,176,023       2,171,540       920,163       671,391  
Operating loss   $ (1,513,148 )    $ (918,200 )    $ (1,952,080 )    $ (698,583 )    $ (168,420 ) 
Sales volumes per day
                                            
Natural gas (MMcf)     99.4       100.4       103.2       110.4       96.5  
Oil (MBbls)     37.9       42.2       42.0       41.6       41.8  
Total (MBOE)     54.5       58.9       59.3       60.0       57.9  
Percent of sales volumes from oil     70 %      72 %      71 %      69 %      72 % 
Average sales price
                                            
Oil per Bbl   $ 40.05     $ 46.11     $ 58.87     $ 47.49     $ 72.70  
Natural gas per Mcf     1.82       2.54       2.55       2.72       3.58  
Gain (loss) on derivative financial instruments per BOE     5.65       10.23       (5.51 )      3.14       35.94  
Total revenues per BOE     36.83       47.57       40.70       41.06       94.40  
Operating expenses per BOE
                                            
Lease operating expense
                                            
Insurance expense     2.00       2.09       1.66       1.64       2.11  
Workover and maintenance     1.33       4.06       2.27       2.00       2.46  
Direct lease operating expense     14.30       11.30       13.40       16.40       17.83  
Total lease operating expense per BOE     17.63       17.45       17.33       20.04       22.40  

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  Quarter Ended
Operating Highlights   December 31,
2015
  September 30,
2015
  June 30,
2015
  March 31,
2015
  December 31,
2014
     (In thousands, except per unit amounts)
Production taxes     0.06       0.14       0.28       0.28       0.42  
Gathering and transportation     3.35       2.76       0.64       0.69       0.90  
Depreciation, depletion and amortization     24.26       22.88       33.99       34.83       32.87  
Accretion of asset retirement obligations     3.18       2.73       2.29       2.24       2.40  
Impairment of oil and natural gas properties     284.48       166.91       343.52       105.56        
Goodwill impairment                             61.80  
General and administrative     5.79       4.09       4.68       6.88       5.21  
Total operating expenses per BOE     338.75       216.96       402.73       170.52       126.00  
Operating loss per BOE   $ (301.92 )    $ (169.39 )    $ (362.03 )    $ (129.46 )    $ (31.60 ) 

Results of Operations

Three Months Ended December 31, 2015 Compared With the Three Months Ended
December 31, 2014

Our consolidated net loss attributable to common stockholders for the three months ended December 31, 2015 was $1,313.4 million or $13.81 diluted net loss per common share (“per share”) as compared to $278.8 million or $2.97 per share for the three months ended December 31, 2014. The increase in the loss was primarily due to the impairment of oil and natural gas properties, lower oil and natural gas sales prices, lower gain on derivative financial instruments and higher interest expense, partially offset by the gain on early extinguishment of debt. In addition, depreciation, depletion and amortization (“DD&A”) and lease operating expenses were lower in the three months ended December 31, 2015 compared to the three months ended December 31, 2014. The three months ended December 31, 2014 also included impairment of goodwill.

Revenues

       
  Three Months Ended
December 31,
  Decrease   Percent
Decrease
     2015   2014
          (In thousands)          
Oil   $ 139,698     $ 279,708     $ (140,010 )      (50.1 )% 
Natural gas     16,615       31,801       (15,186 )      (47.8 )% 
Gain on derivative financial instruments     28,302       191,462       (163,160 )      (85.2 )% 
Total Revenues   $ 184,615     $ 502,971     $ (318,356 )      (63.3 )% 

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Our consolidated revenues decreased $318.4 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower gain on derivative financial instruments and 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

         
  Three Months Ended
December 31,
  Increase
(Decrease)
  Percent
Increase
(Decrease)
  Revenue
Increase
(Decrease)
     2015   2014
                         (In thousands)
Price Variance
                                            
Oil sales prices (per Bbl)   $ 40.05     $ 72.70     $ (32.65 )      (44.9 )%    $ (125,612 ) 
Natural gas sales prices (per Mcf)     1.82       3.58       (1.76 )      (49.2 )%      (15,667 ) 
Gain on derivative financial instruments (per BOE)     5.65       35.94       (30.29 )      (84.3 )%      (163,160 ) 
Total price variance                             (304,439 ) 
Volume Variance
                                            
Oil sales volumes (MBbls)     3,488       3,848       (360 )      (9.3 )%      (14,398 ) 
Natural gas sales volumes (MMcf)     9,145       8,881       264       3.0 %      481  
BOE sales volumes (MBOE)     5,012       5,328       (316 )      (5.9 )%          
Percent of BOE from oil     70 %      72 %                      
Total volume variance                             (13,917 ) 
Total price and volume variance                           $ (318,356 ) 

Price Variances

Commodity prices are one of the key drivers of our earnings and net operating cash flow. Lower commodity prices decreased revenues by $304.4 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year. Average oil prices decreased $32.65 per barrel in the second quarter of fiscal 2016 compared to the second quarter of fiscal 2015, resulting in lower revenues of $125.6 million. Average natural gas prices decreased $1.76 per Mcf in the second quarter of fiscal 2016 compared to the second quarter of fiscal 2015, resulting in lower revenues of $15.7 million. For the second quarter of fiscal 2016, our hedging activities resulted in a gain on derivative activities of $5.65 per BOE compared to a gain of $35.94 per BOE for the same period in the prior fiscal year, resulting in lower revenues of $163.2 million. The gain on derivatives for the quarter ended December 31, 2015 reflects a gain on settlements of our derivative contracts of approximately $6.13 per barrel of oil compared to the gain on settlements and monetization of our derivative contracts of approximately $17.95 per barrel of oil for the quarter ended December 31, 2014.

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 will result in reduced cash from operating activities, potentially causing us to further reduce our capital expenditure program. As a result of our high level of indebtedness and commodity prices, we have significantly reduced our planned capital spending, and such curtailment of the development of our properties will eventually lead to a decline in our production and reserves. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operating activities and the value of our assets.

Volume Variances

Sales volumes are another key driver of our earnings and net operating cash flow. Oil sales volumes decreased 3.9 MBbls per day in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in lower revenues of $14.4 million. Natural gas sales volumes slightly increased by 2.9 Mcfe per day in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in slightly higher revenues of $0.5 million. Sales volumes decreased because of natural well declines,

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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

         
  Three Months Ended December 31,   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   $ 10,042     $ 2.00     $ 11,233     $ 2.11     $ (1,191 ) 
Workover and maintenance     6,656       1.33       13,130       2.46       (6,474 ) 
Direct lease operating expense     71,660       14.30       95,003       17.83       (23,343 ) 
Total lease operating expense     88,358       17.63       119,366       22.40       (31,008 ) 
Production taxes     309       0.06       2,263       0.42       (1,954 ) 
Gathering and transportation     16,778       3.35       4,771       0.90       12,007  
Depreciation, depletion and amortization     121,567       24.26       175,155       32.87       (53,588 ) 
Accretion of asset retirement obligations     15,944       3.18       12,798       2.40       3,146  
Impairment of oil and natural gas properties     1,425,792       284.48                   1,425,792  
Goodwill impairment                 329,293       61.80       (329,293 ) 
General and administrative     29,015       5.79       27,745       5.21       1,270  
Total costs and expenses   $ 1,697,763     $ 338.75     $ 671,391     $ 126.00     $ 1,026,372  
Other (income) expense
                                            
Loss from equity method investees   $     $     $ 1,275     $ 0.24     $ (1,275 ) 
Other income, net     (2,554 )      (0.51 )      (991 )      (0.19 )      (1,563 ) 
Gain on early extinguishment of debt     (290,296 )      (57.92 )                  (290,296 ) 
Interest expense     90,234       18.00       66,901       12.56       23,333  
Total other (income) expense, net   $ (202,616 )    $ (40.43 )    $ 67,185     $ 12.61     $ (269,801 ) 

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Costs and expenses increased $1,026.4 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, principally due to the impairment of oil and natural gas properties of $1,425.8 million and an increase in gathering and transportation expense. Partially offsetting these increases were lower goodwill impairment, DD&A and lease operating expense, principally due to factors discussed further below.

At the end of each quarter, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to our full cost pool of oil and natural gas properties, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. As a result of our ceiling test at December 31, 2015, we recognized a ceiling test impairment of our oil and natural gas properties totaling $1,425.8 million during the quarter ended December 31, 2015.

During the quarter ended December 31, 2014, 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 June 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 of 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 $31.0 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year. 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 $22.40 for the quarter ended December 31, 2014 to $17.63 for the quarter ended December 31, 2015.

Gathering and transportation expense increased $12.0 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year. This increase was primarily due to rent expense associated with the lease of the GIGS, which we entered into on June 30, 2015.

DD&A expense decreased $53.6 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to a decrease in the DD&A per BOE rate of $8.61. The decrease in the DD&A rate in the second quarter of fiscal 2016 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 year 2015 and 2016 resulting from the ceiling test, partially offset by the reduction in proved reserve estimates.

General and administrative expense increased $1.3 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to lower capitalized amounts and an increase in stock-based compensation, partially offset by lower employee salary costs.

Interest expense increased $23.3 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, principally due to interest on the 11.0% Notes, offset somewhat by interest reductions from repurchases of debt. On a per unit of production basis, interest expense increased 43.3%, from $12.56 per BOE to $18.00 per BOE.

During the three months ended December 31, 2015, we repurchased certain of our unsecured notes in aggregate principal amounts as follows: $295.9 million of 6.875% Senior Notes due 2024, $8.2 million of 7.5% Senior Notes due 2021, $25.2 million of 7.75% Senior Notes due 2019 and $25.6 million of 9.25% Senior Notes due 2017. We repurchased these notes in open market transactions at a total cost of approximately $89.9 million, and we recorded a gain on the repurchases totalling approximately $290.3 million, net of associated debt issuance costs and certain other expenses.

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Income Tax Expense

The income tax expense in the second quarter of fiscal 2016 is computed based on our estimated annual effective tax rate for the full fiscal year. We recorded essentially no income tax expense in the second quarter of fiscal 2016 compared to income tax expense of $40.4 million in the second quarter of fiscal 2015. The decrease is primarily due to the book loss for the quarter, the forecast book loss for the year 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. Please see Note 9 — Income Taxes of Notes to Consolidated Financial Statements in this Quarterly Report.

Six Months Ended December 31, 2015 Compared With the Six Months Ended December 31, 2014

Our consolidated net loss attributable to common stockholders for the six months ended December 31, 2015 was $1,889.6 million or $19.91 diluted net loss per common share (“per share”) as compared to $254.5 million or $2.71 per share for the six months ended December 31, 2014. The increase in the loss was primarily due to the impairment of oil and natural gas properties, lower oil and natural gas sales prices, lower gain on derivative financial instruments and higher interest expense, partially offset by the gain on early extinguishment of debt. In addition, DD&A and lease operating expenses were lower in the six months ended December 31, 2015 compared to the six months ended December 31, 2014. The six months ended December 31, 2014 also included impairment of goodwill.

Revenues

       
  Six Months Ended
December 31,
  Decrease   Percent
Decrease
     2015   2014
          (In thousands)          
Oil   $ 318,606     $ 649,863     $ (331,257 )      (51.0 )% 
Natural gas     40,100       66,362       (26,262 )      (39.6 )% 
Gain on derivative financial instruments     83,732       248,187       (164,455 )      (66.3 )% 
Total Revenues   $ 442,438     $ 964,412     $ (521,974 )      (54.1 )% 

Our consolidated revenues decreased $522.0 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to 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

         
  Six Months Ended
December 31,
  Increase
(Decrease)
  Percent Increase
(Decrease)
  Revenue Increase
(Decrease)
     2015   2014
                                           (In thousands)  
Price Variance
                                            
Crude oil sales prices (per Bbl)   $ 43.24     $ 84.49     $ (41.25 )      (48.8 )%    $ (317,249 ) 
Natural gas sales prices (per Mcf)     2.18       3.66       (1.48 )      (40.4 )%      (26,793 ) 
Gain on derivative financial instruments     8.03       23.16       (15.13 )      (65.3 )%      (164,455 ) 
Total price variance                             (508,497 ) 
Volume Variance
                                            
Crude oil sales volumes (MBbls)     7,368       7,692       (324 )      (4.2 )%      (14,008 ) 
Natural gas sales volumes (MMcf)     18,385       18,141       244       1.3 %      531  
BOE sales volumes (MBOE)     10,432       10,716       (284 )      (2.7 )%          
Percent of BOE from crude oil     71 %      72 %                      
Total volume variance                             (13,477 ) 
Total price and volume variance                           $ (521,974 ) 

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Price Variances

Lower commodity prices decreased revenues by $508.5 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year. Average oil prices decreased $41.25 per barrel in the first six months of fiscal 2016 compared to the first six months of fiscal 2015, resulting in lower revenues of $317.2 million. Average natural gas prices decreased $1.48 per Mcf in the first six months of fiscal 2016 compared to the first six months of fiscal 2015, resulting in lower revenues of $26.8 million. For the first six months of fiscal 2016, our hedging activities resulted in a gain on derivative activities of $8.03 per BOE compared to a gain of $23.16 per BOE for the same period in the prior fiscal year, resulting in lower revenues of $164.5 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 compared to the gain on settlements and monetization of our derivative contracts of approximately $9.19 per barrel of oil for the six months ended December 31, 2014.

Volume Variances

Oil sales volumes decreased 1.8 MBbls per day in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in lower revenues of $14.0 million, while natural gas sales volumes slightly increased by 1.3 Mcfe per day in the first six months of fiscal 2016, resulting in higher revenues of $0.5 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

         
  Six Months Ended December 31,   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   $ 21,377     $ 2.05     $ 22,255     $ 2.08     $ (878 ) 
Workover and maintenance     28,684       2.75       42,546       3.97       (13,862 ) 
Direct lease operating expense     132,919       12.74       197,150       18.40       (64,231 ) 
Total lease operating expense     182,980       17.54       261,951       24.45       (78,971 ) 
Production taxes     1,066       0.10       5,356       0.50       (4,290 ) 
Gathering and transportation     31,756       3.04       13,959       1.30       17,797  
DD&A     245,591       23.54       334,295       31.20       (88,704 ) 
Accretion of asset retirement obligations     30,728       2.95       25,617       2.39       5,111  
Impairment of oil and natural gas properties     2,330,461       223.40                   2,330,461  
Goodwill impairment                 329,293       30.73       (329,293 ) 
General and administrative     51,204       4.91       54,169       5.06       (2,965 ) 
Total costs and expenses   $ 2,873,786     $ 275.48     $ 1,024,640     $ 95.63     $ 1,849,146  
Other (income) expense
                                            
Loss from equity method investees   $ 10,746     $ 1.03     $ 316     $ 0.03     $ 10,430  
Other income, net     (3,048 )      (0.29 )      (1,942 )      (0.18 )      (1,106 ) 
Gain on early extinguishment of debt     (748,574 )      (71.76 )                  (748,574 ) 
Interest expense     193,452       18.54       133,164       12.43       60,288  
Total other (income) expense, net   $ (547,424 )    $ (52.48 )    $ 131,538     $ 12.28     $ (678,962 ) 

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Costs and expenses increased $1,849.1 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, principally due to the impairment of oil and natural gas properties of $2,330.5 million and an increase in gathering and transportation expense. Partially offsetting these increases were lower goodwill impairment, DD&A and lease operating expense, principally due to factors discussed further below.

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

As a result of the goodwill impairment test performed at December 31, 2014, 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.

Lease operating expense decreased $79.0 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year. 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 $24.45 for the six months ended December 31, 2014 to $17.54 for the six months ended December 31, 2015.

Gathering and transportation expense increased $17.8 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year. This increase was primarily due to rent expense associated with the lease of the GIGS, which we entered into on June 30, 2015.

DD&A expense decreased $88.7 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to a decrease in the DD&A per BOE rate of $7.66. The decrease in the DD&A rate in the first six months of fiscal 2016 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 year 2015 and 2016 resulting from the ceiling test, partially offset by the reduction in proved reserve estimates.

General and administrative expense decreased $3.0 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to lower employee salary costs, partially offset by lower capitalized amounts and an increase in stock-based compensation.

Interest expense increased $60.3 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, principally due to interest on the 11.0% Notes, offset somewhat by interest reductions from repurchases of debt. On a per unit of production basis, interest expense increased 49.2%, from $12.43 per BOE to $18.54 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 6.875% Senior Notes due 2024, $261.9 million of 7.5% Senior Notes due 2021, $148.9 million of 7.75% Senior Notes due 2019, $29.8 million of 8.25% Senior Notes due 2018 and $29.4 million of 9.25% Senior Notes due 2017. We repurchased these notes in open market transactions at a total cost of approximately $213.1 million, and we recorded a gain on the repurchases totalling approximately $748.6 million, net of associated debt issuance costs and certain other expenses.

Income Tax Expense

The income tax expense in the first six months of fiscal 2016 is computed based on our estimated annual effective tax rate for the full fiscal year. We recorded essentially no income tax expense in the first six months of fiscal 2016 compared to income tax expense of $57.0 million in the first six months of fiscal 2015. The decrease is primarily due to the book loss for the period, the forecast book loss for the year 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 9 — Income Taxes of Notes to Consolidated Financial Statements in this Quarterly Report.

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Liquidity and Capital Resources

Overview

We have historically funded our operations primarily through cash flows from operating activities, borrowings under our revolving credit facility, proceeds from the issuance of debt and equity securities and proceeds from asset sales. However, future cash flows are subject to a number of variables and are highly dependent on the prices we receive for oil and natural gas. Oil and natural gas prices declined severely during fiscal year 2015 and have declined even further through fiscal 2016 to date. The price of WTI crude oil per barrel dropped below $27.00 per barrel in January 2016 for the first time in twelve years. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position.

As of December 31, 2015, we had cash and cash equivalents of approximately $326 million and approximately $122 million of available borrowing capacity under our Revolving Credit Facility. As of December 31, 2015, we had total indebtedness of $3,623.4 million, comprised of $150 million of secured indebtedness outstanding under our Revolving Credit Facility, $1.45 billion of 11.0% Notes, $5 million in other secured indebtedness, $2,084 million of unsecured notes and net unamortized original issue discount of $65.6 million. Due to the continued decreases in commodity prices and our substantial debt burden, the Company continues to incur significant losses and negative cash flows from operating activities.

As of December 31, 2015, we were in compliance with our financial covenants under the Revolving Credit Facility; however, based on current market conditions and depressed commodity prices, if we are unable to execute on one of the strategic alternatives discussed below and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio covenant under our Revolving Credit Facility for the quarter ending March 31, 2016. In addition, as part of our quarterly compliance certificates required under our revolving credit agreement and also as a condition to borrow additional funds or issue letters of credit under our revolving credit agreement, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in our Revolving Credit Facility. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation.

We are evaluating various alternatives with respect to our Revolving Credit Facility, but there is no certainty that we will be able to implement any alternatives or otherwise resolve our covenant issues. If the lenders under the Revolving Credit Facility are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Revolving Credit Facility, and there is no assurance that we will reach an agreement with our lenders on any such amendment or waiver. Absent success in these pursuits, a resultant breach under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

We may face other impediments to accessing our available borrowing capacity under our Revolving Credit Facility. Borrowings under our First Lien Credit Agreement are also limited to a borrowing base based on oil and natural gas reserve values which are redetermined on a periodic basis. During the quarter ended December 31, 2015, we and our lenders completed our fall borrowing base redetermination with no changes to the existing borrowing base. If we experience the continuation of low oil and natural gas prices, or if they decline even further, we anticipate that our Revolving Credit Facility borrowing base and commitment

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amounts will likely be reduced in the spring of 2016 as part of our next borrowing base redetermination, which would adversely impact our liquidity. In addition, we would have to repay any outstanding indebtedness in excess of any reduced borrowing base.

In addition, in response to commodity price declines, our fiscal year 2016 capital budget was reduced to a current planned amount of $130 to $150 million, as compared to actual capital expenditures in fiscal year 2015 (excluding acquisition activity) of approximately $649 million. The curtailment of the development of our properties will eventually lead to a decline in our production and reserves. In addition, due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $336.5 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operating activities and the value of our assets.

We may experience a further strain on our liquidity if the BOEM requires us to provide additional bonding as a means to assure our decommissioning obligations or if the surety companies providing such bonds on our behalf require us to provide additional cash collateral for such 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.

Beginning on January 11, 2016, our common stock has generally traded on NASDAQ at less than $1.00 per share. If at any time our common stock falls below the minimum bid price of $1.00 per share for 30 consecutive business days, NASDAQ will send a deficiency notice to the Company, advising that it has been afforded a “compliance period” of 180 calendar days to regain compliance with the applicable requirements. If the Company is unable to resolve its bid price deficiency during the applicable compliance period, NASDAQ Staff will issue a delisting letter. We cannot assure you that the price of our common stock will comply with the requirements for continued listing of our shares on NASDAQ. A delisting of our common stock could constitute a “fundamental change” under the terms of our $400 million aggregate principal amount of 3.0% Senior Convertible Notes. If a Fundamental Change occurs at any time prior to the maturity of the convertible notes, each holder shall have the right to require the Company to repurchase all or part of such holder’s 3.0% Senior Convertible Notes in a principal amount thereof that is equal to $1,000 in principal amount or whole multiples thereof, on the date (the “Fundamental Change Repurchase Date”) specified by the Company that is not less than 20 nor more than 35 calendar days after the date of the Fundamental Change Company Notice at a repurchase price, payable in cash, equal to 100% of the principal amount of the 3.0% Senior Convertible Notes being repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date. We cannot assure that we would have adequate liquidity to fund a repurchase given the severe liquidity constraints of the Company. Further, such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

As described below under “— Our Indebtedness and Available Credit,” we had total indebtedness of $3,623.4 million as of December 31, 2015, and, taking into account the bond repurchases completed subsequent to December 31, 2015, we had total indebtedness of $2,874.6 million as of February 15, 2016. We expect to have substantial interest payments due on our outstanding bonds in the next twelve months, totalling $247.8 million. In addition, the majority of our outstanding indebtedness will mature within the next ten years, with a substantial portion coming due in the next five years. All of the factors described above have placed considerable pressure on our ability to pay the principal and interest on our long-term debt and to satisfy our

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other liabilities, continue our development activities to maintain and grow reserves and our ability to refinance our debt as it becomes due. As a result of the commodity price decline and the Company’s substantial debt burden, absent a material improvement in oil and gas prices or a refinancing or restructuring of our debt obligations or other improvement in liquidity, the Company believes forecasted cash and expected available credit capacity will not be sufficient to meet commitments as they come due for the next twelve months. This raises substantial doubt regarding the Company’s ability to continue as a going concern.

In February 2016, we engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise management and our Board regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. We are also focused on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows.

As a result of commodity price decline, we will continue to evaluate our ability to make the debt payments in light of our liquidity constraints, but if we are unable to generate sufficient cash flow to service our debt or meet our debt obligations as they become due, we will have to take certain actions described in greater detail elsewhere in this Quarterly Report and in our 2015 Annual Report in “Risk Factors — We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.

On February 16, 2016, the Company elected to enter into the 30-day grace period under the terms of the indenture governing EPL’s 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company will work with its debt holders regarding its ongoing effort to develop and implement a comprehensive plan to restructure its balance sheet.

The election to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes constitutes a default; however, it does not constitute an Event of Default under the indenture governing our 8.25% Senior Notes or the Revolving Credit Facility. As a result of this default, certain restrictions have been placed on the Company, including but not limited to, its ability to incur additional indebtedness, draw on the Revolving Credit Facility and issue additional letters of credit. The Company has 30 days to cure the default by making the required interest payment that was due on February 16, 2016. Alternatively, the Company may restructure the debt with its creditors. On March 17, 2016, if the interest payment default is not cured, the default would be considered an Event of Default and the trustee or the holders of at least 25% in aggregate principal amount of then outstanding 8.25% Senior Notes may declare the principal and accrued interest for all outstanding 8.25% Senior Notes due and payable immediately. An Event of Default would also trigger cross defaults in the Company’s other debt obligations. An Event of Default would have a material adverse effect on the Company’s liquidity, financial condition and results of operations.

Absent a material improvement in oil and gas prices or a refinancing or some restructuring of our debt obligations or other improvement in liquidity, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements.

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Our Indebtedness and Available Credit

As of December 31, 2015, we had total indebtedness of $3,623.4 million as described in greater detail below, comprised of $150 million of secured indebtedness outstanding under our Revolving Credit Facility, $1.45 billion of senior secured second lien notes, $5 million in other secured indebtedness, $2,084 million of unsecured notes and net unamortized original issue discount of $65.6 million. 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 6.875% Senior Notes due 2024, $261.9 million of 7.5% Senior Notes due 2021, $148.9 million of 7.75% Senior Notes due 2019, $29.8 million of 8.25% Senior Notes due 2018 and $29.4 million of 9.25% Senior Notes due 2017. We repurchased these notes in open market transactions at a total cost of approximately $213.1 million. Subsequent to December 31, 2015, we repurchased approximately $737.7 million of our unsecured notes in open market transactions at a total price of approximately $19.2 million, including $16.4 million of accrued interest, reducing our total indebtedness to approximately $2,874.6 million as of February 15, 2016. All of our outstanding indebtedness will mature within the next ten years, with a substantial portion coming due in the next five years. The maturity dates for our outstanding notes are as follows:

9.25% Senior Notes due December 15, 2017 ($249.5 million)
8.25% Senior Notes due February 15, 2018 ($213.7 million)
3.0% Convertible Notes due December 15, 2018 ($400 million)
7.75% Senior Notes due June 15, 2019 ($101.1 million)
11.0% Senior Secured Second Lien Notes due March 15, 2020 ($1.45 billion)
7.50% Senior Notes due December 15, 2021 ($238.1 million)
6.875% Senior Notes due March 15, 2024 ($144 million)

In addition, the maturity of certain of our outstanding indebtedness may be accelerated in certain situations. Pursuant to the indenture governing our 11.0% Notes, we will be required to offer to purchase all outstanding 11.0% Notes if a “triggering event” occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a “triggering event” will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes (December 15, 2017), if on such date the aggregate outstanding principal amount of all such notes exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes (February 15, 2018), if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes exceeds $250.0 million. As a result of our bond repurchases subsequent to December 31, 2015, we have the principal amount of the 8.25% Senior Notes and the 9.25% Senior Notes outstanding to $213.7 million and $249.5 million, respectively, eliminating this springing maturity in the 11.0% Notes. In addition, our Revolving Credit Facility is scheduled to mature on April 9, 2018; however, the maturity of our Revolving Credit Facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017.

For more information regarding the terms of all of our outstanding notes, see Note 6 – Long Term Debt of Notes to Consolidated Financial Statements in this Quarterly Report.

Revolving Credit Facility.  The second amended and restated first lien credit agreement (“First Lien Credit Agreement” or “Revolving Credit Facility”), as amended, has a maximum facility amount and borrowing base of $500 million, of which such amount $150 million is the borrowing base under the sub-facility established for EPL. As of December 31, 2015, we had $150.0 million in borrowings and $227.8 million in letters of credit issued under our First Lien Credit Agreement. The maturity date of the First Lien Credit Agreement is April 9, 2018, provided that certain conditions are met; however, the maturity of our Revolving Credit Facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017. Our Revolving Credit Facility is comprised of a syndicate of large domestic and international banks, with no single lender providing more than 5% of the overall commitment amount.

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As of July 31, 2015, EGC and EPL entered into the Eleventh Amendment and Waiver to the First Lien Credit Agreement (the “Eleventh Amendment”), which waived certain provisions of the First Lien Credit Agreement to permit the M21K acquisition previously discussed as well as an additional minor acquisition and the disposition of the East Cameron pipeline. Further, the Eleventh Amendment temporarily increased the letter of credit commitment amount within the facility from $300 million to a maximum amount of $305 million through August 31, 2015, after which it reduced back to $300 million.

On November 30, 2015, EGC and EPL entered into the Twelfth Amendment to the First Lien Credit Agreement, under which the following changes became effective:

Modification of triggers that require EPL and its subsidiaries to provide guarantees of the indebtedness of EGC and its subsidiaries and grant liens on the assets of EPL and its subsidiaries to secure such guarantees. Under such modifications, such guarantees and security will be required upon the earlier of EPL’s retirement of its obligations in respect of its outstanding 8.25% Senior Notes and amendments to covenant restrictions under such notes that eliminate restrictions on the ability of EPL and its subsidiaries to guarantee the indebtedness of EGC and its subsidiaries and grant liens on the assets of EPL and its subsidiaries to secure such guarantees (even if such notes have not been refinanced or defeased).
Suspending the maximum net secured leverage ratio covenant with respect to EGC and its subsidiaries (other than EPL and its subsidiaries) to begin on the fiscal quarter ending March 31, 2017 rather than March 31, 2015.
Suspending the maximum net secured leverage ratio covenant with respect to EPL and its subsidiaries to begin on the fiscal quarter ending March 31, 2017 rather than March 31, 2015.
Modifying the maximum net secured leverage covenant with respect to EGC and its subsidiaries to be 3.75:1.00 as of the end of each fiscal quarter beginning with the fiscal quarter ended September 30, 2015, increasing to 4.75:1.00 starting March 31, 2016 and to 5.25:1.00 starting June 30, 2016, and decreasing to 5.00:1.00 beginning June 30, 2017 and thereafter.

As amended, the First Lien Credit Agreement requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. EGC is subject to the following financial covenant on a consolidated basis: (a) a minimum current ratio of no less than 1.0 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 as of the end of the fiscal quarter ended December 31, 2015, and increasing to 4.75 to 1.0 starting March 31, 2016 and to 5.25 to 1.00 starting June 30, 2016 and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter. In addition, EGC is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 beginning with the fiscal quarter ending March 31, 2017. In addition, EPL is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 beginning with the fiscal quarter ending March 31, 2017. If EPL’s 8.25% Senior Notes are no longer outstanding and certain other conditions are met, EGC and EPL will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 4.75 to 1.0 as of the end of each fiscal quarter beginning with the fiscal quarter ending March 31, 2016, increasing to 5.25 to 1.0 starting June 30, 2016 and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter, and (c) a minimum current ratio of no less than 1.0 to 1.0.

Since required lender consent to the specific terms of the transaction with respect to the sale of the East Bay field had not been obtained, EGC and EPL were in technical default under the First Lien Credit Agreement at June 30, 2015. On July 14, 2015, we obtained a waiver to this event of default.

In addition to the indebtedness outstanding under the First Lien Credit Agreement, we have substantial additional indebtedness outstanding as previously described above in — Liquidity and Capital Resources — Overview. For more information regarding our outstanding indebtedness, see Note 6 – Long Term Debt of Notes to Consolidated Financial Statements in this Quarterly Report.

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BOEM Bonding Requirements

The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding regulations 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 or letters of credit to support the issuance of such bonds or other surety. Such letters of credit would likely be issued under our Revolving Credit Facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our Revolving Credit Facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require 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 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.

Capital Expenditures

For fiscal 2016, the Company has a target of $130 million to $150 million in capital expenditures including acquisitions and plugging and abandonment obligations. During the six months ended December 31, 2015, our capital expenditures totaled approximately $102 million, of which approximately $41 million, net was spent on development of our core properties and approximately $61 million on other assets. Approximately 41% of our 2016 capital expenditures is expected to be focused on development of our core properties and the remainder on other assets. We intend to fund our capital expenditure program and contractual commitments, including settlement of derivative contracts, from cash on hand, cash flows from operations, and borrowings under our Revolving Credit Facility. If oil and natural gas prices remain at current levels or continue to decline, we may be required to reduce our capital expenditure budget for fiscal year 2016 and future years, which in turn may affect our liquidity and results of operations in future periods. If our cash on hand, cash flows from operations and availability under our Revolving Credit Facility are not sufficient to fund our capital program, we will further reduce our capital spending or otherwise fund our capital needs with proceeds from additional debt and equity or the sale of non-core assets. There is no guarantee that we can access debt and equity capital markets or sell non-core assets at attractive terms. Our capital expenditures and the scope of our drilling activities for fiscal year 2016 may change as a result of several factors, including, but not limited to, changes in oil and natural gas sales prices, costs of drilling and completion operations and drilling results.

Cash Flows

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

   
  Six Months Ended
December 31,
     2015   2014
     (In thousands)
Net cash provided by (used in) operating activities   $ (89,924 )    $ 161,308  
Net cash used in investing activities     (82,872 )      (429,392 ) 
Net cash provided by (used in) financing activities     (258,162 )      223,562  
Net decrease in cash and cash equivalents   $ (430,958 )    $ (44,522 ) 

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Operating Activities

Net cash used in operating activities for the six months ended December 31, 2015 was $89.9 million as compared to $161.3 million provided by operating activities for the six months ended December 31, 2014. The use of cash for operating activities for the six months ended December 31, 2015 compared to cash provided by operating activities for the six months ended December 31, 2014 was due primarily to lower oil and natural gas prices and higher interest expense, partially offset by a reduction of $119.0 million in cash outflows associated with operating assets and liabilities, primarily accounts payable and accrued liabilities.

Investing Activities

For the six months ended December 31, 2015 and 2014, our cash outflows for investing activities were $82.9 million and $429.4 million, respectively. The decrease in cash used in investing activities in the first six months of fiscal 2016 compared to the first six months of fiscal 2015 was primarily due to the reduction in capital expenditures.

Financing Activities

Cash used in financing activities was $258.2 million for the six months ended December 31, 2015 as compared to cash provided by financing activities of $223.6 million for the six months ended December 31, 2014. During the six months ended December 31, 2015, cash used in financing activities consists primarily of $225 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 six months ended December 31, 2014, cash provided by financing activities consists primarily of net proceeds from borrowings of $252.1 million, partially offset by dividends to common and preferred shareholders totaling $28.3 million.

Contractual Obligations

Our contractual obligations at December 31, 2015 did not change materially from those disclosed in Item 7 of our 2015 Annual Report, other than as disclosed in Note 6 — Long-Term Debt and Note 7 — Asset Retirement Obligations of Notes to Consolidated Financial Statements in this Quarterly Report.

Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 — Organization, Summary of Significant Accounting Policies and Recent Accounting Pronouncements of Notes to Consolidated Financial Statements included in our 2015 Annual Report.

Recent Accounting Pronouncements

For a description of recent accounting pronouncements, see Note 1 — Organization, Summary of Significant Accounting Policies and Recent Accounting Pronouncements of Notes to Consolidated Financial Statements in this Quarterly Report.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

General

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2015 Annual Report.

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 includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we were a party at December 31, 2015, and from which we may incur future gains or losses from changes in market interest rates or commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Hypothetical changes in commodity prices and interest rates chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on

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consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Commodity Price Risk

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

Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. We have incurred debt under the borrowing base of our Revolving Credit Facility. This borrowing base is subject to periodic redetermination based in part on changing expectations of future prices. Recently, commodity prices have deteriorated materially. If we experience the continuation of low oil and gas prices, or if they decline even further, we anticipate that our existing Revolving Credit Facility borrowing base and commitment amounts will likely be reduced in the spring of 2016 as part of our next borrowing base redetermination, which would adversely impact our liquidity. In addition, we would have to repay any outstanding indebtedness under the Revolving Credit Facility in excess of any reduced borrowing base. The energy markets have historically been very volatile, and there can be no assurance that crude oil and natural gas prices will improve.

We utilize commodity-based derivative instruments with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. We currently have financially settled crude oil and natural gas zero-cost collars and three-way collars contracts in our hedging portfolio. 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.

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

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As of December 31, 2015, we had the following net open crude oil derivative positions:

         
Remaining Contract Term   Type of
Contract
  Index   Volumes
(MBbls)
  Weighted Average
Contract Price
  Collars/Put
  Floor   Ceiling
January 2016 – June 2016     Collars       NYMEX-WTI       2,548     $ 51.43     $ 74.70  
July 2016 – December 2016     Collars       NYMEX-WTI       2,576       51.43       74.70  

As of December 31, 2015, we had the following net open natural gas derivative position:

           
Remaining Contract Term   Type of
Contract
  Index   Volumes
(MMBtu)
  Weighted Average
Contract Price
  Collars/Put
  Sub
Floor
  Floor   Ceiling
January 2016 – April 2016     Three-Way Collars       NYMEX-HH       1,515     $ 2.43     $ 2.93     $ 4.12  

At December 31, 2015, our crude oil contracts outstanding were in an asset position of $60.7 million. A 10% increase in crude oil prices would reduce the fair value by approximately $13.5 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $15 million. Also at December 31, 2015, our natural gas contracts outstanding were in an asset position of $0.5 million. A 10% increase in natural gas prices would reduce the fair value by approximately $0.1 million, while a 10% decrease in natural gas prices would increase the fair value by approximately $0.1 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2015.

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.

For a complete discussion of our open commodity derivatives as of December 31, 2015, please see Note 8 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to our variable rate debt obligations. Specifically, we are exposed to changes in interest rates as a result of borrowings under our Revolving Credit Facility, and the terms of such facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. We consider our interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 95.9% of our debt. As of December 31, 2015, total debt included $150 million of floating-rate debt. As a result, our period-end interest costs will fluctuate based on short-term interest rates on approximately 4.1% of our total debt outstanding as of December 31, 2015. A 10 percent change in floating interest rates on period-end floating debt balances would change quarterly interest expense by approximately $16,106. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. However, to reduce our future exposure to changes in interest rates, we may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues.

We generally invest cash equivalents in high-quality credit instruments consisting primarily of money market funds with maturities of 90 days or less. We do not expect any material loss from cash equivalents and therefore we believe our interest rate exposure on invested funds is not material.

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ITEM 4. 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 Quarterly Report. 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 and as a result of a material weakness identified during preparation of the Company’s financial statements for the fiscal year ended June 30, 2015 which has not been fully remediated, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of the end of the period covered by this Quarterly Report.

Changes in Internal Control over Financial Reporting

The Board recently implemented additional controls and procedures in response to a material weakness in its control environment identified during the preparation of its financial statements for the fiscal year ended June 30, 2015, including, but not limited to, strengthening the Company’s vendor procurement procedures to address any potential conflicts of interest that could arise between the Company and any of its vendors; amended the Company’s Code of Business Conduct and Ethics to, among other things, include explicit prohibitions and heightened disclosures addressing activities or personal interests that create or appear to create a conflict between personal interests and the interests of the Company and implement a new insider trading policy. The Company is also implementing an enhanced comprehensive training program on these new procedures and policies.

Other than changes related to the items noted above, there was no change in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our quarterly period ended December 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. 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 financial position or results of operations.

ITEM 1A. Risk Factors

Our business faces many risks. Any of the risks discussed in this Quarterly Report or our other SEC filings, could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in our common stock, please refer to the section entitled “Item 1A. Risk Factors” in our 2015 Annual Report. There have been no material changes in the risk factors set forth in our 2015 Annual Report other than those set forth below.

Current commodity prices impact our ability to comply with debt covenants in our Revolving Credit Facility.

We depend on our Revolving Credit Facility for a portion of our future capital needs. Our current Revolving Credit Facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. Due to the continued decreases in commodity prices, the Company continues to incur significant losses and negative cash flows from continuing operations. Oil and natural gas prices declined severely during fiscal year 2015 and have declined even further through fiscal 2016 to date. The price of WTI crude oil per barrel dropped below $27.00 per barrel in January 2016 for the first time in twelve years. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position.

We also are required to comply with certain debt covenants and ratios. Our ability to comply with these restrictions and covenants in the future will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which have declined significantly in the quarter ended December 31, 2015 and further in the current quarter. As of December 31, 2015, we were in compliance with our debt covenants; however, based on current market conditions and depressed commodity prices, if we are unable to adequately address liquidity concerns through one of the strategic alternatives described below, we will not be in compliance with the consolidated net secured leverage ratio covenant under our Revolving Credit Facility for the quarter ending March 31, 2016. We are evaluating various alternatives with respect to our Revolving Credit Facility, but there is no certainty that we will be able to implement any alternatives or otherwise resolve our covenant issues. If the lenders under the Revolving Credit Facility are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Revolving Credit Facility, and there is no assurance that we will reach an agreement with our lenders on any such amendment or waiver.

In addition, as part of our quarterly compliance certificates required under our Revolving Credit Facility and also as a condition to borrow additional funds or issue letters of credit under our Revolving Credit Facility, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in our Revolving Credit Facility. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation.

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We have engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise management and our Board regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness and preferred equity or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all.

Absent success in these pursuits, a resultant breach under the Revolving Credit Facility from covenant non-compliance or our inability to deliver the required solvency representations would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness. As a result, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our financial statements.

We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.

During the second half of 2014 and into 2015, NYMEX-WTI oil prices fell from in excess of $100 per Bbl to below $50 per Bbl, the lowest price since 2009. Over the same period, Henry Hub spot prices for natural gas fell from in excess of $3.00 per MMBtu to below $2.00 per MMBtu. Oil prices have continued to decline in the first calendar quarter of 2016, with the price of WTI crude oil per barrel dropping below $27.00 in January 2016 for the first time in twelve years. These events have adversely impacted our available liquidity.

As of January 29, 2016, we had cash and cash equivalents of approximately $269 million and approximately $122 million of available borrowing capacity under our Revolving Credit Facility, which has a borrowing base of $500 million. As discussed above, as a condition to borrow funds or issue letters of credit under our Revolving Credit Facility, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in our Revolving Credit Facility. As discussed above, absent a material improvement in oil and gas prices or a refinancing or some restructuring of our debt obligations or other improvement in liquidity, we will not be in compliance with the consolidated net secured leverage ratio under the Revolving Credit Facility for the quarter ending March 31, 2016. In addition, the current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required solvency representation. Finally, continuation of hydrocarbon prices at current levels increase the likelihood that our borrowing base will be reduced as part of our next borrowing base redetermination scheduled for the spring of 2016, potentially requiring us to repay amounts under our Revolving Credit Facility if our borrowings under the Revolving Credit Facility exceed the redetermined borrowing base. If low prices continue and we are unable to achieve a restructuring of our debt obligations or other improvement in liquidity, all of these factors will limit our ability to access available borrowing capacity under our Revolving Credit Facility and forecasted cash and expected available credit capacity will not be sufficient to meet commitments as they come due for the next twelve months.

On February 16, 2016, the Company elected to enter into the 30-day grace period under the terms of the indenture governing EPL’s “8.25% Senior Notes” to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company will work with its debt holders regarding its ongoing effort to develop and implement a comprehensive plan to restructure its balance sheet.

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The election to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes constitutes a default; however, it does not constitute an Event of Default under the indenture governing our 8.25% Senior Notes or the Revolving Credit Facility. As a result of this default, certain restrictions have been placed on the Company, including but not limited to, its ability to incur additional indebtedness, draw on the Revolving Credit Facility and issue additional letters of credit. The Company has 30 days to cure the default by making the required interest payment that was due on February 16, 2016. Alternatively, the Company may restructure the debt with its creditors. On March 17, 2016, if the interest payment default is not cured, the default would be considered an Event of Default and the trustee or the holders of at least 25% in aggregate principal amount of then outstanding 8.25% Senior Notes may declare the principal and accrued interest for all outstanding 8.25% Senior Notes due and payable immediately. An Event of Default would also trigger cross defaults in the Company’s other debt obligations. An Event of Default would have a material adverse effect on the Company’s liquidity, financial condition and results of operations.

As discussed in the risk factor above, we are currently evaluating strategic alternatives to address our liquidity issues and high debt levels, but we cannot assure you that any of our strategies will yield sufficient funds to meet our working capital or other liquidity needs, including for payments of interest and principal on our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations. As a result, we may seek protection of the United States Bankruptcy Court (the “Bankruptcy Court”) to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements.

We may seek the protection of the Bankruptcy Court, which may harm our business and place equity holders at significant risk of losing all of their interests in the Company.

We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring. However, a filing under Chapter 11 of the U.S. Bankruptcy Code may be unavoidable. Seeking Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as a proceeding related to a Chapter 11 proceeding continues, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. Bankruptcy Court protection also might make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer a proceeding related to a Chapter 11 proceeding continues, the more likely it is that our customers and suppliers would lose confidence in our ability to reorganize our businesses successfully and would seek to establish alternative commercial relationships.

Additionally, we have a significant amount of secured indebtedness that is senior to our unsecured indebtedness and a significant amount of total indebtedness that is senior to our existing preferred stock and common stock in our capital structure. As a result, we believe that seeking Bankruptcy Court protection under a Chapter 11 proceeding could result in a limited recovery for unsecured noteholders, if any, and place equity holders at significant risk of losing all of their interests in the Company.

If the trading price of our common stock fails to comply with the continued listing requirements of NASDAQ, we could face possible delisting. NASDAQ delisting could materially adversely affect the market for our shares.

Beginning on January 11, 2016, our common stock has generally traded on NASDAQ at less than $1.00 per share. If at any time our common stock falls below the minimum bid price of $1.00 per share for 30 consecutive business days, NASDAQ will send a deficiency notice to the Company, advising that it has been afforded a “compliance period” of 180 calendar days to regain compliance with the applicable requirements. If we are unable to resolve our bid price deficiency during the applicable compliance period, NASDAQ Staff will issue a delisting letter. At that time, the Company may request a hearing before a Hearing Panel, which will stay the delisting.

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We cannot assure you that the price of our common stock will comply with the requirements for continued listing of our shares on NASDAQ. If we receive a deficiency notice, we cannot assure that we will be able to regain compliance or that any appeal of a decision to delist our common stock would be successful. If our common stock loses its listed status on NASDAQ and we are not successful in obtaining a listing on another exchange, our common stock would likely trade only in the over-the-counter market. If our common stock were to trade on the over-the-counter market, selling our common stock could be more difficult because smaller quantities of shares would likely be bought and sold, transactions could be delayed, and security analysts’ coverage of us may be reduced. In addition, in the event our common stock is delisted, broker-dealers have certain regulatory burdens imposed upon them, which may discourage broker-dealers from effecting transactions in our common stock, further limiting the liquidity thereof. These factors could result in lower prices and larger spreads in the bid and ask prices for our common stock.

Moreover, a delisting of our common stock could constitute a “fundamental change” under the terms of our $400 million aggregate principal amount of 3.0% Senior Convertible Notes. If a Fundamental Change occurs at any time prior to the maturity of the convertible notes, each holder shall have the right to require the Company to repurchase all or part of such holder’s notes in a principal amount thereof that is equal to $1,000 in principal amount or whole multiples thereof, on the date (the “Fundamental Change Repurchase Date”) specified by the Company that is not less than 20 nor more than 35 calendar days after the date of the Fundamental Change Company notice at a repurchase price, payable in cash, equal to 100% of the principal amount of the 3% Senior Convertible Notes being repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date. We cannot assure that we would have adequate liquidity to fund a repurchase. Each holder will also have the right to convert its 3% Senior Convertible Notes at any time beginning on the effective date of such transaction and until the close of business on the business day immediately preceding the relevant Fundamental Change Repurchase Date, which might require us to issue a significantly greater number of shares of our common stock for issuance upon conversion of the preferred stock and deplete the number of authorized shares of common stock available for issuance for other purposes. Such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

If we are unable to spend the capital necessary to develop our proved undeveloped reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove the associated volumes from our reported proved reserves, which could adversely affect our results of operations.

At June 30, 2015, approximately 32% of our total estimated proved reserves were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove to be accurate. Our reserve report at June 30, 2015 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $823 million. We cannot be certain the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. If we are unable to spend the capital necessary to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any proved undeveloped reserves not developed within this five-year time frame.

Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but

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were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. A removal of such reserves will adversely affect our results of operations. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $336.5 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization.

We may be required to post additional collateral to satisfy the collateral requirements related to the surety bonds that secure our offshore decommissioning obligations.

To cover the costs for various obligations of lessees on the Outer Continental Shelf (“OCS”), including costs for such decommissioning obligations as the plugging of wells, the removal of platforms and other facilities, the decommissioning of pipelines and the clearing of the seafloor of obstructions typically performed at the end of production, the BOEM generally requires that the lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. Failure to post the requisite bonds or otherwise satisfy the BOEM’s security requirements could have a materially adverse effect on our ability to operate in the U.S. Gulf of Mexico.

Because we are not exempt from the BOEM’s supplemental bonding requirements, we engage a number of surety companies to post the requisite bonds. Pursuant to the terms of our agreements with these surety companies, we are required to post collateral at the outset of the agreement or subsequently on demand, the amount of which typically may be increased at the surety companies’ discretion. Given current commodity prices’ effect on our creditworthiness and the unwillingness of the surety companies to post bonds without the requisite collateral, we cannot assure that we will always be able to satisfy the demands for additional collateral for current bonds or comply with new supplemental bonding requirements. If we fail to do so, we may be in default under our agreements with the surety companies, which in turn could cause a cross-default under our Revolving Credit Facility and potentially our indentures.

We may be required to provide additional letters of credit to support the additional collateral or bonding requirements requested by the BOEM or the surety companies. Such letters of credit would likely be issued under our Revolving Credit Facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases given these new expenses, and if we are unable to obtain the additional required bonds or the increased amount of required collateral as requested, the BOEM may require any or all 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.

New regulatory initiatives imposing more stringent requirements regarding the emission of pollutants, including greenhouse gases, could cause us to incur increased capital expenditures and operating costs, which could be significant.

The federal Clean Air Act and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to result in the emission of new or increased existing air pollutants, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in August 2015, the EPA announced proposed rules, expected to be finalized in 2016, that would establish new controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production activities, as part of an overall effort to reduce methane emissions by up to 45 percent in 2025. In a second example, in October 2015, the EPA issued a final rule under the federal Clean Air Act, lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per million under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in

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Paris, France that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country will use to achieve its greenhouse gas emissions targets. Although it is not possible at this time to predict how new methane or ozone restrictions would impact our business or how or when the United State might impose restrictions on greenhouse gases as a result of the international agreement agreed to in Paris but any new legal requirements that impose more stringent requirements on the emission of pollutants, including greenhouse gases, from our 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.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None

ITEM 3. Defaults upon Senior Securities

None

ITEM 4. Mine Safety Disclosures.

Not applicable

ITEM 5. Other Information

None

ITEM 6. Exhibits

The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this Quarterly Report, and such Exhibit Index is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, Energy XXI Ltd has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
  ENERGY XXI LTD
    

By:

/S/ BRUCE W. BUSMIRE

Bruce W. Busmire
Duly Authorized Officer and Chief Financial Officer

    

By:

/S/ HUGH A. MENOWN

Hugh A. Menown
Duly Authorized Officer and Executive Vice President and Chief Accounting Officer

Date: February 16, 2016

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EXHIBIT INDEX

   
Exhibit Number   Exhibit Description   Incorporated by Reference to the Following
3.1   Altered Memorandum of Association of Energy XXI Ltd   3.1 to the Company’s Form 8-K filed on November 9, 2011
3.2   Bye-Laws of Energy XXI Ltd   3.2 to the Company’s Form 8-K filed on November 9, 2011
10.1     Twelfth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of November 30, 2015   10.1 to the Company’s Form 8-K filed on November 30, 2015
10.2 †   First Amendment to Employment Agreement, dated as of October 15, 2015, by and between the Company and John D. Schiller, Jr.   10.1 to the Company’s Form 8-K filed on October 15, 2015
10.3 †   Form of Restricted Stock Unit Agreement (Chief Executive Officer) under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC   4.4 to the Company’s Form S-8 filed on December 8, 2015
10.4 †   Form of Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC   4.5 to the Company’s Form S-8 filed on December 8, 2015
10.5 †   Form of TSR Outperformance Restricted Stock Unit Agreement (Chief Executive Officer) under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC   4.6 to the Company’s Form S-8 filed on December 8, 2015
10.6 †   Form of TSR Outperformance Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC   4.7 to the Company’s Form S-8 filed on December 8, 2015
10.7 †   Energy XXI Services, LLC Long-Term Performance Cash Incentive Plan   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   Furnished 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

(†) Executive Compensation Plan or Arrangement

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