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 September 30, 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 October 30, 2015, there were 94,967,121 shares outstanding of the registrant’s common stock, par value $0.005 per share.

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ENERGY XXI LTD
 
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		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			39
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			53
ITEM 4. Controls and Procedures			55
PART II — OTHER INFORMATION
ITEM 1. Legal Proceedings			57
ITEM 1A. Risk Factors			57
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			57
ITEM 3. Defaults upon Senior Securities			57
ITEM 4. Mine Safety Disclosures			57
ITEM 5. Other Information			57
ITEM 6. Exhibits			57
SIGNATURES			58
EXHIBIT INDEX			59

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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 September 30, 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:

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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)

		September 30, 2015				June 30, 2015
		(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents		$	491,461			$	756,848
Accounts receivable
Oil and natural gas sales			75,902				100,243
Joint interest billings			19,979				12,433
Other			35,105				43,513
Prepaid expenses and other current assets			49,053				24,298
Restricted cash			9,708				9,359
Derivative financial instruments			50,904				22,229
Total Current Assets			732,112				968,923
Property and Equipment
Oil and natural gas properties, net – full cost method of accounting, including $437.8 million and $436.4 million of unevaluated properties not being amortized at September 30, 2015 and June 30, 2015, respectively			2,691,510				3,570,759
Other property and equipment, net			22,599				21,820
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment			2,714,109				3,592,579
Other Assets
Derivative financial instruments			8,658				3,898
Equity investments			—				10,835
Restricted cash			32,682				32,667
Other assets and debt issuance costs, net of accumulated amortization			71,068				81,927
Total Other Assets			112,408				129,327
Total Assets		$	3,558,629			$	4,690,829
LIABILITIES
Current Liabilities
Accounts payable		$	175,994			$	156,339
Accrued liabilities			135,425				155,306
Asset retirement obligations			27,366				33,286
Derivative financial instruments			—				2,661
Current maturities of long-term debt			6,230				11,395
Total Current Liabilities			345,015				358,987
Long-term debt, less current maturities			4,007,081				4,597,037
Asset retirement obligations			505,806				453,799
Derivative financial instruments			—				1,358
Other liabilities			5,000				8,370
Total Liabilities			4,862,902				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)

		September 30, 2015				June 30, 2015
		(Unaudited)
Commitments and Contingencies (Note 15)
Stockholders’ Deficit
Preferred stock, $0.001 par value, 7,500,000 shares authorized at September 30, 2015 and June 30, 2015
7.25% Convertible perpetual preferred stock, 3,000 shares issued and outstanding at September 30, 2015 and June 30, 2015			—				—
5.625% Convertible perpetual preferred stock, 797,759 and 812,759 shares issued and outstanding at September 30, 2015 and June 30, 2015, respectively			1				1
Common stock, $0.005 par value, 200,000,000 shares authorized and 94,966,655 and 94,643,498 shares issued and outstanding at September 30, 2015 and June 30, 2015, respectively			474				472
Additional paid-in capital			1,844,611				1,843,918
Accumulated deficit			(3,149,359	)			(2,573,113	)
Total Stockholders’ Deficit			(1,304,273	)			(728,722	)
Total Liabilities and Stockholders’ Deficit		$	3,558,629			$	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 September 30,
		2015				2014
Revenues
Oil sales		$	178,908			$	370,155
Natural gas sales			23,485				34,561
Gain on derivative financial instruments			55,430				56,725
Total Revenues			257,823				461,441
Costs and Expenses
Lease operating			94,622				142,585
Production taxes			757				3,093
Gathering and transportation			14,978				9,188
Depreciation, depletion and amortization			124,024				159,140
Accretion of asset retirement obligations			14,784				12,819
Impairment of oil and natural gas properties			904,669				—
General and administrative expense			22,189				26,424
Total Costs and Expenses			1,176,023				353,249
Operating Income (Loss)			(918,200	)			108,192
Other Income (Expense)
(Loss) income from equity method investees			(10,746	)			959
Other income, net			494				951
Gain on early extinguishment of debt			458,278				—
Interest expense			(103,218	)			(66,263	)
Total Other Income (Expense), net			344,808				(64,353	)
Income (Loss) Before Income Taxes			(573,392	)			43,839
Income Tax Expense (Benefit)			—				16,649
Net Income (Loss)			(573,392	)			27,190
Preferred Stock Dividends			2,854				2,872
Net Income (Loss) Attributable to Common Stockholders		$	(576,246	)		$	24,318
Earnings (Loss) per Share
Basic		$	(6.08	)		$	0.26
Diluted		$	(6.08	)		$	0.24
Weighted Average Number of Common Shares Outstanding
Basic			94,778				93,833
Diluted			94,778				102,300

 
 
See accompanying Notes to Consolidated Financial Statements.

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

		Three Months Ended September 30,
		2015				2014
Cash Flows From Operating Activities
Net income (loss)		$	(573,392	)		$	27,190
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			124,024				159,140
Impairment of oil and natural gas properties			904,669				—
Deferred income tax expense			—				16,369
Gain on early extinguishment of debt			(458,278	)			—
Change in fair value of derivative financial instruments			(36,688	)			(55,095	)
Accretion of asset retirement obligations			14,784				12,819
Loss (income) from equity method investees			10,746				(959	)
Amortization and write-off of debt issuance costs and other			5,581				2,744
Deferred rent			2,288				—
Stock-based compensation			383				1,779
Changes in operating assets and liabilities
Accounts receivable			39,606				23,313
Prepaid expenses and other assets			(14,122	)			7,661
Settlement of asset retirement obligations			(40,631	)			(14,907	)
Accounts payable and accrued liabilities			(48,203	)			23,896
Net Cash Provided by (Used in) Operating Activities			(69,233	)			203,950
Cash Flows from Investing Activities
Acquisitions, net of cash			(2,227	)			(287	)
Capital expenditures			(68,656	)			(280,010	)
Insurance payments received			976				—
Change in equity method investments			—				1,282
Transfer to restricted cash			(12	)			—
Proceeds from the sale of properties			3,787				6,947
Other			112				(80	)
Net Cash Used in Investing Activities			(66,020	)			(272,148	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs			311				2,217
Dividends to shareholders – common			—				(11,264	)
Dividends to shareholders – preferred			(2,863	)			(2,872	)
Proceeds from long-term debt			—				510,120
Payments on long-term debt			(99,792	)			(454,042	)
Payment of debt assumed in acquisition			(25,187	)			—
Fees related to debt extinguishment			(1,580	)			—
Debt issuance costs			(4	)			(2,250	)
Other			(1,019	)			(17	)
Net Cash Provided by (Used in) Financing Activities			(130,134	)			41,892
Net Decrease in Cash and Cash Equivalents			(265,387	)			(26,306	)
Cash and Cash Equivalents, beginning of period			756,848				145,806
Cash and Cash Equivalents, end of period		$	491,461			$	119,500

 
 
See accompanying Notes to Consolidated Financial Statements.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — Organization and Summary of Significant Accounting Policies

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 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.

Note 2 — 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 2 — 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. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

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 September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805) —  Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. It also requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. 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 prospectively. We are currently evaluating the provisions of ASU 2015-16 and assessing the impact, if any, it may have on our consolidated financial statements.

Note 3 — Acquisitions

Acquisition of interest in M21K

On August 11, 2015, pursuant to the M21K Purchase Agreement, 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

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 3 — Acquisitions  – (continued)

had owned a 20% interest in M21K through our investment in EXXI M21K, a wholly owned subsidiary of Energy XXI. 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):

		September 30, 2015				June 30, 2015
Oil and natural gas properties
Proved properties		$	9,385,207			$	9,243,737
Less: accumulated depreciation, depletion, amortization and impairment			(7,131,491	)			(6,109,335	)
Proved properties, net			2,253,716				3,134,402
Unevaluated properties			437,794				436,357
Oil and natural gas properties, net			2,691,510				3,570,759
Other property and equipment			47,896				45,941
Less: accumulated depreciation			(25,297	)			(24,121	)
Other property and equipment, net			22,599				21,820
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment		$	2,714,109			$	3,592,579

At September 30, 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). Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) ratably over a period of time of not more than four years.

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net 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. At September 30, 2015, our ceiling test computation resulted in an impairment of our oil and natural gas properties of $904.7 million. If the current low commodity price environment or downward trend in oil prices continues, there is a reasonable

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 4 — Property and Equipment  – (continued)

likelihood that we could 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 is 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 $10.7 million and equity income of $1.0 million for the three months ended September 30, 2015 and September 30, 2014, respectively.

Note 6 — Long-Term Debt

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

		September 30, 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			510,000				510,000
6.875% Senior Notes due 2024			439,893				650,000
3.0% Senior Convertible Notes due 2018			400,000				400,000
7.5% Senior Notes due 2021			246,271				500,000
7.75% Senior Notes due 2019			126,273				250,000
9.25% Senior Notes due 2017			746,185				750,000
4.14% Promissory Note due 2017			4,231				4,343
Debt premium, 8.25% Senior Notes due 2018(1)			26,018				29,459
Original issue discount, 11.0% Notes due 2020			(49,080	)			(51,104	)
Original issue discount, 3.0% Senior Convertible Notes due 2018			(42,821	)			(45,782	)
Derivative instruments premium financing			5,421				10,647
Capital lease obligations			920				869
Total debt			4,013,311				4,608,432
Less current maturities			6,230				11,395
Total long-term debt		$	4,007,081			$	4,597,037

During the quarter ended September 30, 2015, we repurchased approximately $210.1 million, $253.7 million, $123.7 million and $3.8 million in aggregate principal amount of the 6.875% Senior Notes

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

due 2024, the 7.5% Senior Notes due 2021, the 7.75% Senior Notes due 2019 and the 9.25% Senior Notes due 2017, respectively, in open market transactions at a total price of approximately $123.2 million, and we recorded a gain on the repurchase of approximately $458.3 million, which amount is net of associated debt issuance costs. As of September 30, 2015, note repurchases totalling approximately $28.8 million had not yet settled and are reflected in accrued liabilities. During October 2015, we repurchased an additional $231.4 million, $5.2 million, $25.6 million, $8.2 million and $29.8 million in aggregate principal amount of the 6.875% Senior Notes due 2024, the 7.75% Senior Notes due 2019, the 9.25% Senior Notes due 2017, the 7.5% Notes due 2021, and the 8.25% Notes due 2018, respectively, in open market transactions at a total price of approximately $72.6 million. We will record a gain on these repurchases of approximately $227.8 million, less the amount of associated debt issuance costs, during the three months ended December 31, 2015. The repurchased notes were cancelled. From July 1, 2015 through October 31, 2015, we repurchased approximately $891.5 million of our unsecured notes in open market transactions at a total price of approximately $195.8 million, reducing our total indebtedness to approximately $3,712 million as of October 31, 2015.

Maturities of long-term debt as of September 30, 2015 are as follows (in thousands):

Twelve Months Ended September 30,
2016		$	6,230
2017			1,257,003
2018			153,524
2019			526,273
2020			1,450,000
Thereafter			686,164
			4,079,194
Less: Net original issue discount and debt premium			(65,883	)
Total debt		$	4,013,311

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement” or “Revolving Credit Facility”) was entered into by EGC in May 2011 and underwent its Eleventh Amendment and Waiver to the First Lien Credit Agreement on July 31, 2015 (the “Eleventh Amendment”). This facility, as amended, has a maximum facility amount and borrowing base of $500 million, of which such amount $150 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement. 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.

Borrowings are limited to a borrowing base based on oil and natural gas reserve values which are re-determined on a periodic basis. We and our lenders are currently in the process of our fall borrowing base redetermination, which we expect to conclude during December 2015. 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 become guarantors of the EGC indebtedness under the First Lien Credit Agreement)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

proved reserves and proved developed producing reserves, but with the threshold for such properties of EPL and its subsidiaries (until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) at 85%.

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.

Under the First Lien Credit Agreement, as amended, EGC’s rights to make distributions to its shareholders and pay dividends to parent entities (including ultimately to Energy XXI) are substantially reduced. Generally, under the First Lien Credit Agreement, as amended, 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 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, as amended, 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 minimum current ratio of no less than 1.0 to 1.0. 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. In addition, EPL is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum secured leverage ratio of no more than 3.75 to 1.0. 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 3.75 to 1.0, provided that if the 8.25% Senior Notes are refinanced with new secured debt, the liens of which are junior in priority to the Revolving Credit Facility indebtedness, then the maximum ratio permitted would be 4.25 to 1.0, 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, which waiver required EPL to deposit $21 million into an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement. Such amount will remain on deposit until the next redetermination of the borrowing base, unless used to repay a borrowing base deficiency. Upon the next redetermination, any amounts remaining in the account will be used to make an immediate payment toward

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(Unaudited)

Note 6 — Long-Term Debt  – (continued)

any borrowing base deficiency at the time of such redetermination, and so long as no event of default shall have occurred, any amount remaining after payment in full of any borrowing base deficiency shall be released and paid to EGC.

As of September 30, 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. As part of our quarterly compliance certificates required under our revolving credit agreement and also as a condition to borrow 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, as amended to date. 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. In addition, based on projected market conditions and commodity prices, we currently expect that we will not be in compliance with certain covenants under the First Lien Credit Agreement in certain future periods, including periods prior to June 30, 2016. We continue to focus on reducing our leverage and are working with our bank group on certain amendments to our First Lien Credit Agreement to address these concerns. There can be no assurance any of these discussions or transactions will prove successful. 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 could 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 may 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 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 12.000%. 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 15^th and September 15^th, beginning September 15, 2015. EGC incurred underwriting and direct offering costs of $41.7 million which were recorded as debt issuance costs. The 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.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

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 “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 30^th 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 30^th 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. 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Long-Term Debt  – (continued)

8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL's obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

6.875% Senior Notes Due 2024

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

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

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(Unaudited)

Note 6 — Long-Term Debt  – (continued)

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 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.

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

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(Unaudited)

Note 6 — Long-Term Debt  – (continued)

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.

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

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ENERGY XXI LTD
 
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(Unaudited)

Note 6 — Long-Term Debt  – (continued)

financing. As of September 30, 2015 and June 30, 2015, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $5.4 million and $10.6 million, respectively.

Interest Expense

For the three months ended September 30, 2015 and 2014, interest expense consisted of the following (in thousands):

		Three Months Ended September 30,
		2015				2014
Revolving Credit Facility		$	3,810			$	6,893
11.0% Senior Secured Second Lien Notes due 2020			40,203				—
8.25% Senior Notes due 2018			10,519				10,519
6.875% Senior Notes due 2024			11,032				11,172
3.0% Senior Convertible Notes due 2018			3,025				3,025
7.50% Senior Notes due 2021			7,785				9,375
7.75% Senior Notes due 2019			3,761				4,844
9.25% Senior Notes due 2017			17,344				17,344
4.14% Promissory Note due 2017			44				52
Amortization of debt issue cost – Revolving Credit Facility			676				977
Accretion of original debt issue discount, 11.0% Notes due 2020			2,024				—
Amortization of debt issue cost – 11.0% Notes due 2020			1,635				—
Amortization of fair value premium – 8.25% Senior Notes due 2018			(3,441	)			(2,534	)
Amortization of debt issue cost – 6.875% Senior Notes due 2024			282				281
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018			2,961				2,755
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018			379				353
Amortization of debt issue cost – 7.50% Senior Notes due 2021			230				263
Amortization of debt issue cost – 7.75% Senior Notes due 2019			85				97
Amortization of debt issue cost – 9.25% Senior Notes due 2017			703				552
Derivative instruments financing and other			161				295
		$	103,218			$	66,263

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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			5,234
Liabilities settled			(40,631	)
Accretion expense			14,784
Total balance at September 30, 2015			533,172
Less: current portion			27,366
Long-term balance at September 30, 2015		$	505,806

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 financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from changes in fair value of 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 financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). We include contracts indexed to 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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Note 8 — Derivative Financial Instruments  – (continued)

As of September 30, 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								Sub Floor				Floor				Ceiling
October 2015 – December 2015			Three-Way Collars				ARGUS-LLS				1,840			$	32.50			$	45.00			$	75.00
October 2015 – December 2015			Collars				ARGUS-LLS				460								80.00				123.38
October 2015 – December 2015			Collars				NYMEX-WTI				138								75.00				85.00
October 2015 – December 2015			Bought Put				NYMEX-WTI				276								90.00
October 2015 – December 2015			Sold Put				NYMEX-WTI				(276	)							90.00
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 September 30, 2015, we had the following net open natural gas derivative position:

Remaining Contract Term		Type of Contract				Index				Volumes (MMBtu)				Swaps Fixed Price				Weighted Average Contract Price
																		Collars/Put
																		Sub Floor				Floor				Ceiling
October 2015 – December 2015			Swaps				NYMEX-HH				396			$	4.31
October 2015 – December 2015			Three-Way Collars				NYMEX-HH				1,380							$	2.50			$	3.00			$	4.26
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
		September 30, 2015								June 30, 2015								September 30, 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			$	66,728				Current			$	51,024				Current			$	15,824				Current			$	31,456
			Non-Current				10,409				Non-Current				11,980				Non-Current				1,751				Non-Current				9,440
Total gross derivative financial instruments subject to enforceable master netting agreement							77,137								63,004								17,575								40,896
Derivative financial instruments			Current				(15,824	)			Current				(28,795	)			Current				(15,824	)			Current				(28,795	)
			Non-Current				(1,751	)			Non-Current				(8,082	)			Non-Current				(1,751	)			Non-Current				(8,082	)
Gross amounts offset in Balance Sheets							(17,575	)							(36,877	)							(17,575	)							(36,877	)
Net amounts presented in Balance Sheets			Current				50,904				Current				22,229				Current				—				Current				2,661
			Non-Current				8,658				Non-Current				3,898				Non-Current				—				Non-Current				1,358
						$	59,562							$	26,127							$	—							$	4,019

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(Unaudited)

Note 8 — Derivative Financial Instruments  – (continued)

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

		Three Months Ended September 30,
Gain (loss) on derivative financial instruments		2015				2014
Cash Settlements, net of purchased put premium amortization		$	18,742			$	(1,734	)
Proceeds from monetizations			—				3,364
Change in fair value			36,688				55,095
Total gain on derivative financial instruments		$	55,430			$	56,725

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 September 30, 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 months ended September 30, 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 $2.6 million for the three months ended September 30, 2015. During the three months ended September 30, 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. However, 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 as no statutory exclusion is available. The Alternative Minimum Tax (“AMT”) only allows offset of 90% of AMT income by NOL carryovers (with certain limited

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Note 9 — Income Taxes  – (continued)

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.

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.

Earlier this year, our Board of Directors decided to suspend the declaration of quarterly dividends on our common stock for the foreseeable future, including for the three months ended September 30, 2015. During the three months ended September 30, 2014, we paid cash dividends of $0.12 per share to holders of our common stock.

As of September 30, 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 September 30, 2015, the conversion rate was 10.4765 common shares per preferred share. On or after December 15, 2013, we may cause the

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Note 10 — Stockholders’ Equity  – (continued)

5.625% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of our common 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 September 30, 2015, the conversion rate was 9.3439 common shares per preferred share. On or after December 15, 2014, we may cause the 7.25% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of our common stock equals or exceeds 150% of the then-prevailing conversion price.

Conversions of Preferred Stock

During the three months ended September 30, 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.

Note 11 — Supplemental Cash Flow Information

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

		Three Months Ended September 30,
		2015				2014
Cash paid for interest		$	134,346			$	41,827
Cash paid for income taxes			—				280

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

		Three Months Ended September 30,
		2015				2014
Financing of insurance premiums		$	—			$	3,358
Changes in capital expenditures accrued in accounts payable			12,792				28,346
Changes in asset retirement obligations			71,934				4,207
Note repurchases not yet settled reflected in accrued liabilities			(28,824	)			—

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.

At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due employees will be settled in either common shares or cash. 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

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Note 12 — Employee Benefit Plans  – (continued)

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.

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

		Three Months Ended September 30,
		2015				2014
Restricted Stock Units		$	(3,080	)		$	970
Performance Units			311				(5,175	)
Total compensation expense recognized		$	(2,769	)		$	(4,205	)

As of September 30, 2015, we had 6,793,085 unvested Restricted Stock Units and 855,917 Time-Based Performance Units and 520,667 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 months ended September 30, 2014, we received $0.9 million 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 months ended September 30, 2014, we received management fees of $0.9 million. 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 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 three months ended September 30, 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

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Note 13 — Related Party Transactions  – (continued)

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. This discretionary portion of the success fee was accrued during the three months ended September 30, 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 his earlier 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 — Earnings (Loss) per Share

Basic earnings (loss) per share of common stock is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the 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 earnings (loss) per share (“EPS”) (in thousands, except per share data):

		Three Months Ended September 30,
		2015				2014
Net income (loss)		$	(573,392	)		$	27,190
Preferred stock dividends			2,854				2,872
Net income (loss) attributable to common stockholders		$	(576,246	)		$	24,318
Weighted average shares outstanding for basic EPS			94,778				93,833
Add dilutive securities			—				8,467
Weighted average shares outstanding for diluted EPS			94,778				102,300
Earnings (loss) per share
Basic		$	(6.08	)		$	0.26
Diluted		$	(6.08	)		$	0.24

For the three months ended September 30, 2015, 9,107,588 common stock equivalents were excluded from the diluted average shares due to an anti-dilutive effect. For the three months ended September 30, 2014, no common stock equivalents were excluded from the diluted average shares due to an anti-dilutive effect.

Note 15 — Commitments and Contingencies

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

Letters of Credit and Performance Bonds.  As of September 30, 2015, we had $225 million in letters of credit to third parties relating to assets in the Gulf of Mexico and $379.7 million of performance bonds outstanding. As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (OCS), approximately $218.0 million of our performance bonds are lease and/or area bonds issued to the BOEM (including $60.4 million associated with our August 2015 acquisition of the remaining equity interests in M21K) that 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 including certain state regulatory bodies of certain of the wells and facilities on these leases pursuant to a

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Note 15 — Commitments and Contingencies  – (continued)

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, we reached agreements with the BOEM pursuant to which we provided $150 million of supplemental bonds issued to the BOEM (which is reflected in the $218.0 million in lease and/or area bonds discussed above), and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental financial assurance and/or bonding obligations. 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.

Since our June 2015 agreements with the BOEM, we have worked towards preparing a long-term financial assurance plan that we could submit to the BOEM for approval. We have held meetings with the BOEM in furtherance of the plan’s development and, while a version of the long-term financial assurance plan could be submitted by November 15, 2015, we are currently seeking a 30-day extension to the November 15, 2015 date in order to augment the final plan in light of new information received.

In October 2015, we received information from the BOEM indicating that, following November 15, 2015, we may 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 are no longer exempt from supplemental bonding as a result of co-owners losing their exemptions. We believe that a substantial portion of the additional supplemental financial assurance and/or bonding that may 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. Our request for a 30-day extension from the November 15, 2015 date for submittal of the long-term financial assurance plan is in part to give us time to evaluate and address these potential additional liabilities. 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.

Consequently, 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 after November 15, 2015 if these items are not otherwise addressed in our long-term financial assurance plan. If we are successful in obtaining the 30-day extension, we intend for our long-term financial assurance plan to address these additional financial assurance requirements for which we received information in October 2015. Please note 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.

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

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Note 15 — Commitments and Contingencies  – (continued)

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 plan to submit 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 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 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 terminated, and such action 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 September 30, 2015, our restricted cash included $10 million in cash collateral associated with our bonding requirements, $5 million related to the Grand Isle Gathering System (“GIGS”) transaction, $21 million related to the East Bay sale which will remain restricted until our next borrowing base redetermination 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.

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.

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ENERGY XXI LTD
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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:

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 months ended September 30, 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 September 30, 2015				As of June 30, 2015				As of September 30, 2015				As of June 30, 2015
Assets:
Oil and natural gas derivatives		$	—			$	—			$	77,137			$	63,004
Liabilities:
Oil and natural gas derivatives		$	—			$	—			$	17,575			$	40,896
Restricted stock units			2,452				6,325				—				—
Time-based performance units			222				1,978				—				—
Total liabilities		$	2,674			$	8,303			$	17,575			$	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):

		September 30, 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			1,400,920				684,226				1,398,896				1,276,000
8.25% Senior Notes due 2018			536,018				138,955				539,459				306,000
6.875% Senior Notes due 2024			439,893				77,483				650,000				211,250
3.0% Senior Convertible Notes due 2018			357,179				44,316				354,218				94,000
7.5% Senior Notes due 2021			246,271				44,575				500,000				164,925
7.75% Senior Notes due 2019			126,273				25,111				250,000				92,135
9.25% Senior Notes due 2017			746,185				179,383				750,000				413,160
		$	4,002,739			$	1,344,049			$	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 September 30, 2015 are not material.

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

		Three Months Ended September 30,
		2015				2014
Liabilities:
Performance-based performance units
Balance at beginning of period		$	33			$	6,910
Vested			—				—
Grants charged to general and administrative expense			(32	)			(6,069	)
Balance at end of period		$	1			$	841

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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):

		September 30, 2015				June 30, 2015
Prepaid expenses and other current assets
Advances to joint interest partners		$	5,935			$	1,294
Insurance			17,624				3,427
Inventory			7,476				7,867
Royalty deposit			3,156				3,137
Other			14,862				8,573
Total prepaid expenses and other current assets		$	49,053			$	24,298
Accrued liabilities
Advances from joint interest partners			3,148				3,060
Employee benefits and payroll			7,941				18,927
Interest payable			46,746				83,384
Accrued hedge payable			1,174				1,399
Undistributed oil and gas proceeds			21,984				19,776
Severance taxes payable			746				843
Note repurchases not yet settled			28,824				—
Other			24,862				27,917
Total accrued liabilities		$	135,425			$	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)

		September 30, 2015
		EXXI Bermuda Parent				EGC Issuer				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Reclassifications & Eliminations				Consolidated
		(In Thousands)
ASSETS
Current Assets
Cash and cash equivalents		$	33,947			$	455,953			$	2,655			$	—			$	(1,094	)		$	491,461
Accounts receivable
Oil and natural gas sales			—				—				56,915				23,095				(4,108	)			75,902
Joint interest billings			—				5,750				1,416				12,813				—				19,979
Other			—				14,037				1,981				19,087				—				35,105
Prepaid expenses and other current assets			70				30,899				4,347				13,737				—				49,053
Restricted cash			—				—				350				9,358				—				9,708
Derivative financial instruments			—				48,934				—				1,970				—				50,904
Total Current Assets			34,017				555,573				67,664				80,060				(5,202	)			732,112
Property and Equipment
Oil and natural gas properties, net			—				—				1,644,207				1,047,819				(516	)			2,691,510
Other property and equipment, net			—				—				1,652				20,947				—				22,599
Total Property and Equipment, net			—				—				1,645,859				1,068,766				(516	)			2,714,109
Other Assets
Derivative financial instruments			—				8,658				—				—				—				8,658
Equity investments			—				—				—				3,003,465				(3,003,465	)			—
Intercompany receivables			125,286				1,664,398				—				59,812				(1,849,496	)			—
Restricted cash			—				10,007				—				22,675				—				32,682
Other assets and debt issuance costs, net			176,481				444,096				832				8,092				(558,433	)			71,068
Total Other Assets			301,767				2,127,159				832				3,094,044				(5,411,394	)			112,408
Total Assets		$	335,784			$	2,682,732			$	1,714,355			$	4,242,870			$	(5,417,112	)		$	3,558,629
LIABILITIES
Current Liabilities
Accounts payable		$	—			$	29,415			$	72,539			$	79,115			$	(5,075	)		$	175,994
Accrued liabilities			3,992				73,894				21,294				146,695				(110,450	)			135,425
Deferred income taxes			24,174				—				—				—				(24,174	)			—
Asset retirement obligations			—				—				11,527				15,839				—				27,366
Current maturities of long-term debt			—				3,737				—				2,493				—				6,230
Total Current Liabilities			28,166				107,046				105,360				244,142				(139,699	)			345,015
Long-term debt, less current maturities			357,179				2,959,542				—				935,360				(245,000	)			4,007,081
Intercompany notes payable			—				—				—				555,329				(555,329	)			—
Asset retirement obligations			—				50				309,752				203,311				(7,307	)			505,806
Accumulated losses in excess of equity investments			1,254,712				538,455				—				—				(1,793,167	)			—
Intercompany payables			—				—				1,715,192				6,751				(1,721,943	)			—
Other liabilities			—				5				3				4,992				—				5,000
Total Liabilities			1,640,057				3,605,098				2,130,307				1,949,885				(4,462,445	)			4,862,902
Stockholders’ Equity (Deficit)
Preferred stock
7.25% Convertible perpetual preferred stock			—				—				—				—				—				—
5.625% Convertible perpetual preferred stock			1				—				—				—				—				1
Common stock			474				1				—				12				(13	)			474
Additional paid-in capital			1,844,611				2,236,827				114,825				7,362,469				(9,714,121	)			1,844,611
Accumulated deficit			(3,149,359	)			(3,159,194	)			(530,777	)			(5,069,496	)			8,759,467				(3,149,359	)
Total Stockholders’ Equity (Deficit)			(1,304,273	)			(922,366	)			(415,952	)			2,292,985				(954,667	)			(1,304,273	)
Total Liabilities and Stockholders’ Equity (Deficit)		$	335,784			$	2,682,732			$	1,714,355			$	4,242,870			$	(5,417,112	)		$	3,558,629

TABLE OF CONTENTS

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

TABLE OF CONTENTS

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 September 30, 2015
		EXXI Bermuda Parent				EGC Issuer				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Reclassifications & Eliminations				Consolidated
		(In thousands)
Revenues
Oil sales		$	—			$	—			$	92,318			$	95,102			$	(8,512	)		$	178,908
Natural gas sales			—				—				10,867				12,618				—				23,485
Gain on derivative financial instruments			—				52,561				91				2,778				—				55,430
Total Revenues			—				52,561				103,276				110,498				(8,512	)			257,823
Costs and Expenses
Lease operating			—				1,916				53,296				47,919				(8,509	)			94,622
Production taxes			—				9				407				341				—				757
Gathering and transportation			—				—				15,052				—				(74	)			14,978
Depreciation, depletion and amortization			—				—				65,624				58,466				(66	)			124,024
Accretion of asset retirement obligations			—				—				8,043				6,922				(181	)			14,784
Impairment of oil and natural gas properties			—				—				546,386				308,161				50,122				904,669
General and administrative expense			3,074				4,174				7,822				7,119				—				22,189
Total Costs and Expenses			3,074				6,099				696,630				428,928				41,292				1,176,023
Operating Income (Loss)			(3,074	)			46,462				(593,354	)			(318,430	)			(49,804	)			(918,200	)
Other Income (Expense)
Income (loss) from equity method investees			(568,503	)			(987,735	)			(9,687	)			(563,202	)			2,118,381				(10,746	)
Other income (expense) – net			4,550				8,881				3				4,500				(17,440	)			494
Gain on early extinguishment of debt			—				458,278				—				—				—				458,278
Interest expense			(6,365	)			(88,028	)			(63	)			(32,953	)			24,191				(103,218	)
Total Other Income (Expense)			(570,318	)			(608,604	)			(9,747	)			(591,655	)			2,125,132				344,808
Income (Loss) Before Income Taxes			(573,392	)			(562,142	)			(603,101	)			(910,085	)			2,075,328				(573,392	)
Income Tax Expense (Benefit)			—				—				—				—				—				—
Net Income (Loss)			(573,392	)			(562,142	)			(603,101	)			(910,085	)			2,075,328				(573,392	)
Preferred Stock Dividends			2,854				—				—				—				—				2,854
Net Income (Loss) Attributable to Common Stockholders		$	(576,246	)		$	(562,142	)		$	(603,101	)		$	(910,085	)		$	2,075,328			$	(576,246	)