10-K/A

 

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

 

FORM 10-K/A
Amendment No. 1

 

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

For the fiscal year ended June 30, 2014

or

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

For the transition period from          to         

Commission file number: 001-33628

 

Energy XXI LTD

(Exact name of registrant as specified in its charter)

 

Bermuda	98-0499286
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

Registrant’s telephone number, including area code: (441)-295-2244

 

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, par value $0.005 per share	NASDAQ Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

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

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

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

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

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

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

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $925,761,391 based on the closing sale price of $27.06 per share as reported on The NASDAQ Global Select Market on December 31, 2013, the last business day of the registrant’s most recently completed second fiscal quarter.

The number of shares of the registrant’s common stock outstanding on July 31, 2014 was 93,865,377.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2014 Annual Meeting of Shareholders, which was filed on October 10, 2014, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

EXPLANATORY NOTE

This Amendment No. 1 (“Amendment No. 1”) to the Annual Report of Energy XXI Ltd (the “Company”) on Form 10-K for the fiscal year ended June 30, 2014 (the “Annual Report”) is filed with the Securities and Exchange Commission (the “SEC”) to amend Item 8 “Financial Statements and Supplementary Data” to include a new Note 23 – Supplemental Guarantor Information (the “Consolidating Footnote”), which includes condensed consolidating financial information for the Company, combined guarantor subsidiaries and combined non-guarantor subsidiaries in accordance with the requirements of Regulation S-X. The primary purpose of the Consolidating Footnote is to allow investors to determine the assets, results of operations and comprehensive income (loss) and cash flows of each of the consolidating groups.

This Amendment solely modifies Part II, Item 8, of the Annual Report to include Note 23. All of the information in this Amendment No. 1 is as of August 25, 2014, the date the Company filed the Annual Report with the SEC. This Amendment No. 1 continues to speak as of the date of the Annual Report and does not reflect any subsequent information or events other than the amendment to Item 8 discussed above. Accordingly, this Amendment No. 1 should be read in conjunction with our filings made with the SEC subsequent to the filing of the Annual Report, including any amendments to those filings. Among other things, forward-looking statements made in the Annual Report have not been revised to reflect events, results or developments that occurred or facts that became known to us after the date of the Annual Report.

The certifications pursuant to Section 302 and Section 906 of the Sarbanes-Oxley Act of 2002, filed as Exhibits 31.1, 31.2 and 32.1 to the Annual Report, have been re-executed and re-filed as of the date of this Amendment No. 1.

The Company’s management has considered whether the addition of the Consolidating Footnote to conform to the requirements of Rule 3-10 of Regulation S-X under the Exchange Act affects management’s conclusion, set forth in the Annual Report, regarding the effectiveness, as of June 30, 2014, of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) and the Company’s internal control over financial reporting, (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Management continues to believe that, as of June 30, 2014:

• The Company’s disclosure controls and procedures were functioning effectively to provide reasonable assurance that information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms and (ii) accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure; and

• The Company’s internal control over financial reporting was effective based on the criteria on which it was evaluated, as described in the Annual Report. Management’s Report on Internal Control over Financial Reporting is included in this Amendment No. 1.

PART II

Item 8. Financial Statements and Supplementary Data

	Page
Management’s Report on Internal Control over Financial Reporting		2
Reports of Independent Registered Public Accounting Firm		3
Consolidated Financial Statements
Consolidated Balance Sheets		5
Consolidated Statements of Income		7
Consolidated Statements of Comprehensive Income (Loss)		8
Consolidated Statements of Stockholders’ Equity		9
Consolidated Statements of Cash Flows		10
Notes to Consolidated Financial Statements		11

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed by management, under the supervision of our principal executive and principal financial officers, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the U.S. (“U.S. GAAP”) and includes those policies and procedures that:

• Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management, under the supervision and participation of our principal executive officer and our principal financial officer, assessed the effectiveness of our internal control over financial reporting as of June 30, 2014. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (1992). Management has excluded EPL Oil & Gas, Inc. (“EPL”) from its assessment of internal control over financial reporting as of June 30, 2014 as it was acquired by the Company in a business combination on June 3, 2014. EPL is our wholly-owned indirect subsidiary whose total assets and total revenues represent 47% and 5%, respectively, of the related consolidated financial statements amounts as of and for the year ended June 30, 2014.

Based on this assessment, our management has concluded that, as of June 30, 2014, our internal control over financial reporting was effective based on those criteria.

UHY LLP, the independent registered public accounting firm that audited the consolidated financial statements included in this Form 10-K, has issued a report on our internal control over financial reporting as of June 30, 2014. This report, dated August 25, 2014, appears on the following page.

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and
Stockholders of Energy XXI (Bermuda) Limited

We have audited Energy XXI (Bermuda) Limited and subsidiaries’ (the “Company”) internal control over financial reporting as of June 30, 2014, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included herein. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Energy XXI (Bermuda) Limited and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of June 30, 2014, based on criteria established in Internal Control — Integrated Framework (1992) issued by COSO.

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

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Energy XXI (Bermuda) Limited and subsidiaries as of June 30, 2014 and 2013, and the related consolidated statements of income, comprehensive income (loss), stockholders’ equity and cash flows for each of the three fiscal years in the period ended June 30, 2014, and our report dated August 25, 2014 expressed an unqualified opinion on those consolidated financial statements.

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

3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and
Stockholders of Energy XXI (Bermuda) Limited

We have audited the accompanying consolidated balance sheets of Energy XXI (Bermuda) Limited (a Bermuda Corporation) and subsidiaries (the “Company”) as of June 30, 2014 and 2013, and the related consolidated statements of income, comprehensive income (loss), stockholders’ equity and cash flows for each of the three fiscal years in the period ended June 30, 2014. Our audit also included the financial statement schedule included in Item 15(a)(2). The Company’s management is responsible for these consolidated financial statements and schedule. Our responsibility is to express an opinion on these consolidated financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Energy XXI (Bermuda) Limited and subsidiaries as of June 30, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three fiscal years in the period ended June 30, 2014, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Energy XXI (Bermuda) Limited and subsidiaries’ internal control over financial reporting as of June 30, 2014, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated August 25, 2014 expressed an unqualified opinion on the effective operation of internal control over financial reporting.

/s/ UHY LLP
Houston, Texas
August 25, 2014, except for Note 23, as to
which the date is December 23, 2014

4

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

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

 
 
See accompanying Notes to Consolidated Financial Statements

5

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

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

 
 
See accompanying Notes to Consolidated Financial Statements

6

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

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

 
 
See accompanying Notes to Consolidated Financial Statements

7

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

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

 
 
See accompanying Notes to Consolidated Financial Statements

8

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

	Preferred Stock			Common Stock			Treasury Stock			Paid-in Capital			Accumulated (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
	5.625%		7.25%
Balance, June 30, 2011	$	1		$	381					$	1,479,959		$	(465,160	)	$	(68,484	)	$	946,697
Common stock issued, net of direct costs					1						10,051									10,052
Common stock based compensation					2						11,758									11,760
Preferred stock converted to common					12						(12	)
Common stock dividends														(5,516	)					(5,516	)
Preferred stock dividends														(13,028	)					(13,028	)
Preferred stock inducement											29			(6,068	)					(6,039	)
Comprehensive income														335,827			126,087			461,914
Balance, June 30, 2012		1			396						1,501,785			(153,945	)		57,603			1,405,840
Common stock issued, net of direct costs					1						7,021									7,022
Common stock based compensation											3,505									3,505
Repurchase of company common stock							$	(72,663	)											(72,663	)
Common stock dividends														(25,992	)					(25,992	)
Preferred stock dividends														(11,496	)					(11,496	)
Comprehensive income														162,081			(31,051	)		131,030
Balance, June 30, 2013		1			397			(72,663	)		1,512,311			(29,352	)		26,552			1,437,246
Common stock issued, net of direct costs					81						341,478									341,559
Common stock based compensation											6,711									6,711
Repurchase of company common stock								(170,266	)											(170,266	)
Treasury stock retired					(10	)		52,966			(52,956	)								—
Common stock reissued								189,963			(32,030	)		(3,216	)					154,717
Discount on convertible debt											61,948									61,948
Common stock dividends														(34,680	)					(34,680	)
Preferred stock dividends														(11,489	)					(11,489	)
Comprehensive income														59,111			(47,027	)		12,084
Balance, June 30, 2014	$	1		$	468		$	—		$	1,837,462		$	(19,626	)	$	(20,475	)	$	1,797,830

 
 
See accompanying Notes to Consolidated Financial Statements

9

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

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

 
 
See accompanying Notes to Consolidated Financial Statements

10

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies

Nature of Operations.  Energy XXI (Bermuda) Limited was incorporated in Bermuda on July 25, 2005. Headquartered in Houston, Texas, we are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico.

References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

Principles of Consolidation and Reporting.  The accompanying consolidated financial statements include the accounts of Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported consolidated net income, consolidated stockholders’ equity or consolidated cash flows.

Use of Estimates.  The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such difference may be material.

Cash and Cash Equivalents.  We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents.

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

Accounts Receivable and Allowance for Doubtful Accounts.  Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2014 and 2013, no allowance for doubtful accounts was necessary.

Oil and Natural Gas Properties.  We use the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

portion of our acquisition costs to unevaluated properties based on fair value. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict.

Depreciation, Depletion and Amortization.  The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method.

Weather Based Insurance Linked Securities.  We obtain Weather Based Insurance Linked Securities (“Securities”), to mitigate potential loss to our oil and natural gas properties from hurricanes in the Gulf of Mexico. These Securities provide for payments of negotiated amounts should a pre-defined category hurricane pass within specific pre-defined areas encompassing our oil and natural gas producing fields. Since these Securities were obtained to mitigate potential loss due to hurricanes in the Gulf of Mexico, the majority of the premiums associated with these Securities are charged to expense during the period associated with the hurricane season, typically June 1 to November 30. The amortization of insurance premiums for these Securities is recorded as a component of our lease operating expense.

Other Property and Equipment.  Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years. Repairs and maintenance costs are expensed in the period incurred.

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

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

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Derivative Instruments.  We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Gains or losses resulting from transactions designated as cash flow hedges are recorded at market value and are recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of income as the physical production hedged by the contracts is delivered. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized directly in earnings.

The net cash flows related to any recognized gains or losses associated with cash flow hedges are reported as oil and natural gas revenue and presented in cash flow from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contract is delivered.

Debt Issuance Costs.  Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the scheduled maturity of the debt utilizing the straight-line method, which approximates the interest method.

Asset Retirement Obligations.  Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

Common Stock.  Refers to the $0.005 par value per share capital stock as designated in the Company’s Certificate of Incorporation. Treasury Stock is accounted for using the cost method.

Revenue Recognition.  We recognize oil and natural gas revenue under the entitlement method of accounting. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices.

General and Administrative Expense.  Under the full cost method of accounting, a portion of our general and administrative expense that is directly identified with our acquisition, exploration and development activities is capitalized as part of oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to directly support those employees that are directly involved in acquisition, exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities.

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Our capitalized general and administrative expense directly related to our acquisition, exploration and development activities for the years ended June 30, 2014, 2013 and 2012 was $64.5 million, $37.6 million and $38.3 million, respectively.

Share-Based Compensation.  Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period.

Income Taxes.  Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate.

When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate any tax operating loss and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized in our consolidated financial statements. At June 30, 2014 we maintained a $22.5 million valuation allowance against our net deferred tax assets due to our judgment that our existing State of Louisiana net operating loss (“NOL”) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly. In light of our capital structure, U.S. withholding taxes attributable to interest due on loans from the Bermuda parent to the U.S. operating companies is provided as the interest accrues. This U.S. withholding tax (at 30%) is due when the interest is actually paid, and may not be offset or reduced by U.S. operating activity; although the interest expense is generally deductible in the U.S. when paid, subject to certain other limitations.

We adopted the provisions of ASC Topic 740-10 (formally known as FIN 48, addressing “Uncertain Tax Positions”) and applied this guidance as of July 1, 2007. As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of ASC Topic 740-10 nor have we recorded any gross unrecognized tax benefit related to Uncertain Tax Positions.

Earnings per Share.  The Earnings per Share (“EPS”) amounts have been calculated based on the weighted-average number of shares of common stock outstanding for the year. Diluted EPS reflects the potential dilution, using the treasury stock method. The diluted EPS calculation includes shares of common stock from the assumed conversion of the Company’s redeemable preferred stock.

Note 2 — Recent Accounting Pronouncements

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We adopted ASU 2011-11 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

In February 2013, the FASB issued Accounting Standards Update No. 2013-02: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 updates ASU 2011-12 and requires companies to report information of significant changes in accumulated balances of

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 — Recent Accounting Pronouncements  – (continued)

each component of other comprehensive income included in equity in one place. Total changes in accumulated other comprehensive income by component can either be presented on the face of the financial statements or in the notes. ASU 2013-02 is effective for fiscal years and interim periods within those years beginning after December 15, 2012, with early adoption permitted. We adopted ASU 2013-02 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

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

Note 3 — Acquisitions and Dispositions

ExxonMobil oil and gas properties interests acquisition

On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“ExxonMobil”) for a total cash consideration of approximately $32.8 million. The GOM Interests cover 5,000 gross acres on Vermilion Block 164 (“VR 164”). We are the operator of these properties. In addition to acquiring the GOM Interests, we entered into a joint venture agreement with ExxonMobil to explore for oil and gas on nine contiguous blocks adjacent to VR 164 in shallow waters on the GOM shelf. We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012. The objective targets at Pendragon well, the initial prospect, were not reached as it encountered mechanical issues and was plugged and abandoned. Subsequently, we began drilling the Merlin well located at Vermilion Block 179; the Merlin well did not encounter any commercial hydrocarbons and was plugged and abandoned. We are currently negotiating an extension of our joint venture with ExxonMobil to further the Pendragon and Merlin wells’ data along with reprocessing the 3D seismic information to determine the future drilling activities on the Vermilion Block.

Revenues and expenses related to the GOM Interests from the closing date of October 17, 2012 are included in our consolidated statements of income. The acquisition of the GOM Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on October 17, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	10,447
Oil and natural gas properties – unevaluated		27,721
Asset retirement obligations		(5,351	)
Cash paid	$	32,817

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

Dynamic Offshore oil and gas properties interests acquisition

On November 7, 2012, we acquired 100% of the interests (“Dynamic Interests”) held by Dynamic Offshore Resources, LLC (“Dynamic”) on VR 164 for approximately $7.2 million.

Revenues and expenses related to the Dynamic Interests from the closing date of November 7, 2012 are included in our consolidated statements of income. The acquisition of the Dynamic Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	1,753
Oil and natural gas properties – unevaluated		6,571
Asset retirement obligations		(1,091	)
Cash paid	$	7,233

McMoRan oil and gas properties interests acquisition

On January 17, 2013, we closed on the acquisition of certain onshore Louisiana interests in the Bayou Carlin field (“Bayou Carlin Interests”) from McMoRan Oil and Gas, LLC (“McMoRan”) for a total cash consideration of $79.3 million. This acquisition was effective as of January 1, 2013. We are the operator of these properties.

Revenues and expenses related to the Bayou Carlin Interests from the closing date of January 17, 2013 are included in our consolidated statements of income. The acquisition of the Bayou Carlin Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	62,499
Oil and natural gas properties – unevaluated		17,184
Asset retirement obligations		(382	)
Cash paid	$	79,301

RoDa oil and gas properties interests acquisition

On March 14, 2013, we acquired 100% of the interests (“RoDa Interests”) held by RoDa Drilling LP (“RoDa”) in the Bayou Carlin field for $32.7 million. This acquisition was effective as of January 1, 2013.

Revenues and expenses related to the RoDa Interests from the closing date of March 14, 2013 are included in our consolidated statements of income. The acquisition of the RoDa Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 14, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	32,777
Asset retirement obligations		(115	)
Cash paid	$	32,662

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

Tammany oil and gas properties interests acquisition

On June 28, 2013, we closed on the acquisition of certain offshore Louisiana interests in the West Delta field (“West Delta Interests”) from Tammany Energy Ventures, LLC (“Tammany”) for a total cash consideration of $8.3 million. This acquisition was effective as of June 1, 2013. We are the operator of these properties.

Revenues and expenses related to the West Delta Interests are included in our consolidated statements of income from July 1, 2013. The acquisition of West Delta Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on June 28, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	8,626
Asset retirement obligations		(338	)
Cash paid	$	8,288

Black Elk Interest

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

Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of income from December 20, 2013. The acquisition of West Delta 30 Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 (in thousands):

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

* Net working capital includes payables.

Walter Oil & Gas Corporation oil and gas properties interests acquisition

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

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of income from March 7, 2014. The acquisition of South Timbalier 54 Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):

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

The fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions were measured using valuation techniques that convert future cash flows to a single discounted amount. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

Apache Joint Venture

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

The area of mutual interest under this Exploration Agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million of which approximately $33.7 million was incurred through June 30, 2014. Drilling on the first well commenced in May 2013 on the southern flank of the salt dome, penetrating eight oil sands and one gas bearing sand. In February 2014 we commenced drilling an offset well which also encountered multiple hydrocarbon bearing sands. Presently both the wellbores have been suspended for future utility and we expect to complete 3D wide azimuth (“WAZ”) seismic data analysis in December 2014. As of June 30, 2014, our share of costs related to these wells was approximately $28.1 million.

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

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

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

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

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

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

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

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

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

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

a. EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.

b. Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37 percent tax rate, which reflected the 35 percent federal statutory rate and a 2 percent weighted-average of the applicable statutory state tax rates (net of federal benefit).

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

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

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

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

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

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

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

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

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

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

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

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

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

a. Exclude $43.3 million of EPL’s exploration costs, impairment expense and gain on sales of assets accounted for under the successful efforts method of accounting to correspond with EXXI’s full cost method of accounting.

b. Increase DD&A expense by $64.2 million for the EPL Properties to correspond with EXXI’s full cost method of accounting.

c. Increase interest expense by $47.8 million to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under EXXI’s revolving credit facility for approximately eleven months ended June 3, 2014. Decrease interest expense $13.7 million to reflect non-cash interest expense associated with the $510 million of EPL’s 8.25% Senior Notes due to the adjustment to fair value of the assumed EPL debt obligations.

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

a. Include net earnings of $57.6 million which represents incremental revenues, lease operating and other direct operating expenses related to EPL’s acquisitions and divestitures from July 1, 2012 to the date of such transactions.

b. Increase DD&A expense by $116.0 million for the EPL Properties to correspond with EXXI’s full cost method of accounting.

c. Increase interest expense by $51.9 million to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under EXXI’s revolving credit facility for the twelve months ending June 30, 2013. Decrease interest expense $7.0 million to reflect non-cash interest expense associated with the $510 million of EPL’s 8.25% Senior Notes due to the adjustment to fair value of the assumed EPL debt obligations, net of interest expense of $5.4 million to reflect interest on the 8.25% Senior Notes from July 1, 2012.

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

Sale of Oil and Natural Gas properties interests

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

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

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

Note 4 — Property and Equipment

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

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

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

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

The Company’s investment in unevaluated properties primarily relates to the unevaluated oil and gas properties acquired in oil and gas property acquisitions, exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. Costs associated with these unevaluated properties are transferred to evaluated properties upon the earlier of (i) when a determination is made whether there are any proved reserves related to the properties, or (ii) amortized over a period of time of not more than four years.

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Property and Equipment  – (continued)

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

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

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

Note 5 — Equity Method Investments

20% interest in Energy XXI M21K, LLC

We own a 20% interest in EXXI M21K. EXXI M21K engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K, LLC (“M21K”).

On June 4, 2012, M21K entered into a Purchase and Sale Agreement (“PSA Agreement”) with EP Energy E&P Company, L.P. (“EP Energy”) to acquire interests in certain oil and natural gas fields owned by EP Energy. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was $103 million. The effective date of the acquisition was January 1, 2012.

On July 19, 2012, M21K closed on the acquisition and we paid our share of the remaining purchase price of $16 million to EP Energy, prior to final adjustments. EXXI M21K is a guarantor of a $100 million first lien credit facility agreement entered into by M21K (“M21K First Lien Credit Agreement”). Simultaneous with the closing of the acquisition of assets from EP Energy, M21K entered into the First Amendment to the M21K First Lien Credit Agreement, which made technical changes to defined terms and hedging requirements, as well as established the borrowing base under the facility at $25 million.

On December 12, 2012, in conjunction with the name change from Natural Gas Partners Assets, LLC to M21K, LLC, M21K entered into the Second Amendment to the M21K First Lien Credit Agreement to reflect the name change and make technical changes to borrowing procedures.

On April 9, 2013, M21K entered into the Third Amendment to the M21K First Lien Credit Agreement that made technical modification of a defined term and reduced the borrowing base to $24 million with a further reduction to $20 million within ninety days from the amendment date.

On July 25, 2013 M21K entered into a PSA Agreement with LLOG Exploration Offshore, L.L.C. (“LLOG Exploration”) to acquire interests in certain oil and natural gas fields owned by LLOG Exploration. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was $103 million. The effective date of the acquisition was April 1, 2013. In connection with this acquisition, M21K paid LLOG Exploration a performance deposit of $10.3 million. On August 30, 2013, M21K closed on the acquisition and paid the remaining purchase price of $70.5 million to LLOG Exploration. Our share of the purchase price was approximately $16.2 million.

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Equity Method Investments  – (continued)

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

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

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

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

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

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

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

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

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

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

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

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

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt

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

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

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

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

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

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by EGC, in May 2011 and underwent its Eighth Amendment on June 3, 2014 as noted below. This facility, as amended, has lender commitments of $1.7 billion and matures on April 9, 2018, provided that the facility will mature immediately if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Borrowings are limited to a borrowing base of $1.5 billion, which is based on oil and natural gas reserve values which are re-determined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, EGC is allowed to pay us a limited amount of distributions, subject to certain terms and conditions. The First Lien Credit Agreement, as amended, requires the consolidated EGC to maintain certain financial covenants. Specifically, EGC may not permit the following under First Lien Credit Agreement: (a) EGC’s total leverage ratio to be more than 3.5 to 1.0, (b) EGC’s

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

interest coverage ratio to be less than 3.0 to 1.0, and (c) EGC’s current ratio (in each case as defined in the First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, EGC is subject to various other covenants including, but not limited to, those limiting its ability to declare and pay dividends or other payments, its ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

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

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

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

The Eighth Amendment also incorporates a few additional changes, including the incorporation of the concept of EGC’s 6.875% Senior Notes due 2024 and EPL’s 8.25% Senior Notes due 2018 as senior unsecured debt generally permitted under the terms of the First Lien Credit Agreement, so that provisions under the First Lien Credit Agreement for such notes are commensurate with the provisions already existing for EGC’s 9.25% senior unsecured notes due 2017, 7.75% senior unsecured notes due 2019 and 7.50% senior unsecured notes due 2021. With the Eighth Amendment, EGC retains the ability to further incur $1 billion of

26

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

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

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

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

High Yield Facilities

8.25% Senior Notes Due 2018

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

27

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

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

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

6.875% Senior Notes Due 2024

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

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

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

EGC believes that the fair value of the $650 million of 6.875% Senior Notes outstanding as of June 30, 2014 was $663 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 6.875% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

3.0% Senior Convertible Notes due 2018

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

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

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

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

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

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

29

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

7.5% Senior Notes Due 2021

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

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

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

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

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

9.25% Senior Notes

On December 17, 2010, EGC issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). It exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act of 1933, as amended (the “Securities Act”), on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from any equity raised. EGC incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

30

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.

EGC believes that the fair value of the $750 million of 9.25% Senior Notes outstanding as of June 30, 2014 was $806.6 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 9.25% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

7.75% Senior Notes

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

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised. EGC incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.

EGC believes that the fair value of the $250 million of 7.75% Senior Notes outstanding as of June 30, 2014 was $269.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 7.75% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

Guarantee of Securities Issued by EGC

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

4.14% Promissory Note

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

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase from our hedge counterparties. Substantially all of our hedges are with lenders under our revolving credit facility. Derivative instruments

31

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-Term Debt  – (continued)

premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value net of derivative instrument premium financing. As of June 30, 2014 and June 30, 2013, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $21 million and $24.7 million, respectively.

Interest Expense

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

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

32

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7 — Notes Payable

In May 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $26.0 million and bore interest at an annual rate of 1.556%. The note matured and was repaid on December 26, 2012.

In July 2012, we entered into a note to finance a portion of our insurance premiums. The note was for a total face amount of $3.6 million and bore interest at an annual rate of 1.667%. The note matured and was repaid on May 1, 2013.

In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums. The note was for a total face amount of $0.6 million and bore interest at an annual rate of 1.774%. The note matured and was repaid on October 23, 2013.

In May 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $24.8 million and bore interest at an annual rate of 1.623%. The note matured and was repaid on April 26, 2014.

On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015. The balance outstanding as of June 30, 2014 was $22.0 million.

Note 8 — Asset Retirement Obligations

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

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

Note 9 — Derivative Financial Instruments

We enter into hedging transactions with a diversified group of investment-grade rated counterparties, primarily financial institutions, for our derivative transactions to reduce the concentration of exposure to any individual counterparty and to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. The Company designates a majority of its derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled.

When the Company discontinues cash flow hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, changes to fair value accumulated in other comprehensive income are recognized immediately into earnings.

33

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

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

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. During the quarter ended September 30, 2011, the Company began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By including Brent benchmarks in our crude hedging, we can more appropriately manage our exposure and price risk. In April 2014 we began including Argus-LLS futures collars in our hedging portfolio to appropriately align and manage our exposure and price risk to market conditions.

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

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

We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended June 30, 2013, and received $181.3 million. These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts. As of June 30, 2014, all of the monetized amounts remaining in OCI were recognized in income.

During the year ended June 30, 2013, we repositioned certain hedge positions by selling puts on certain existing calendar year 2013 hedge collar contracts and purchasing new put spread contracts. The $2.2 million received from the sale of puts were recorded as deferred hedge revenue and were recognized in income over the life of the underlying hedge contracts through December 31, 2013. As of June 30, 2014, all of the amounts remaining in deferred hedge revenue were recognized in income.

34

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

As of June 30, 2014, we had the following net open crude oil derivative positions:

							Weighted Average Contract Price
							Swaps		Collars/Put Spreads
Period	Type of Contract		Index		Volumes (MBbls)		Fixed Price		Sub Floor		Floor		Ceiling
July 2014 – December 2014		Three-Way Collars		Oil-Brent-IPE		766			$	69.00	$	89.00	$	124.99
July 2014 – December 2014		Put Spreads		Oil-Brent-IPE		431				66.43		86.43
July 2014 – December 2014		Collars		Oil-Brent-IPE		368						90.00		108.38
July 2014 – December 2014		Put Spreads		NYMEX-WTI		1,230				70.00		90.00
July 2014 – December 2014		Put		NYMEX-WTI		460						90.00
July 2014 – December 2014		Roll Swap		NYMEX-WTI		2,295	$	1.03
July 2014 – December 2014		Three-Way Collars		NYMEX-WTI		610				70.00		90.00		137.20
July 2014 – December 2014		Swaps		ARGUS-LLS		1,614		92.84
January 2015 – December 2015		Three-Way Collars		Oil-Brent-IPE		3,650				71.00		91.00		113.75
January 2015 – December 2015		Swaps		Oil-Brent-IPE		548		97.70
January 2015 – December 2015		Collars		ARGUS-LLS		1,825						80.00		123.38
January 2015 – December 2015		Put		NYMEX-WTI		1,813						88.76
January 2015 – December 2015		Roll Swap		NYMEX-WTI		3,180		1.03

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

Weighted Average Contract Price

Swaps

Collars/Put Spreads

Period

Type of Contract

Index

Volumes (MMBtu)

Fixed Price

Sub Floor

Floor

Ceiling

July 2014 – December 2014

Three-Way Collars

NYMEX-HH

8,187

$

3.36

$

4.00

$

4.60

July 2014 – December 2014

Put Spreads

NYMEX-HH

1,013

3.25

4.00

July 2014 – December 2014

Swaps

NYMEX-HH

920

$

4.01

January 2015 – December 2015

Swaps

NYMEX-HH

1,570

4.31

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

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

35

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

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

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

The cash flow hedging relationship of our derivative instruments was as follows (in thousands):

Location of (Gain) Loss	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Year Ended June 30, 2014
Commodity Derivative Instruments	$	47,027
Revenues			$	(6,640	)
Loss (gain) on derivative financial instruments						$	6,339
Total	$	47,027	$	(6,640	)	$	6,339
Year Ended June 30, 2013
Commodity Derivative Instruments	$	31,051
Revenues			$	(25,876	)
Loss (gain) on derivative financial instruments						$	881
Total	$	31,051	$	(25,876	)	$	881

36

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

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

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

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

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

37

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Derivative Financial Instruments  – (continued)

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

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $24.9 million ($16.2 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At June 30, 2014, we had no deposits for collateral with our counterparties.

Note 10 — Stockholders’ Equity

Common Stock

On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, our common stock was admitted for trading on The NASDAQ Global Select Market (“NASDAQ”). Our common stock trades on the NASDAQ and on the Alternative Investment Market of the London Stock Exchange (“AIM”) under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. We have 200,000,000 authorized common shares, par value of $0.005 per share.

We paid quarterly cash dividends of $0.07 per share to holders of our common stock on September 14, 2012, December 14, 2012 and March 15, 2013 to shareholders of record on August 31, 2012, November 30, 2012 and March 1, 2013, respectively, and paid quarterly cash dividends of $0.12 per share to holders of our common stock on June 14, 2013, September 13, 2013, December 13, 2013, March 14, 2014 and June 13, 2014, to shareholders of record on May 31, 2013, August 30, 2013, November 29, 2013, February 28, 2014 and May 30, 2014, respectively.

On July 16, 2014, our Board of Directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of our common stock. The quarterly dividend will be paid on September 12, 2014 to shareholders of record on August 29, 2014.

In May 2013, our Board of Directors approved a stock repurchase program authorizing us to repurchase up to $250 million in value of our common stock for an extended period of time, in one or more open market transactions. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity and other appropriate factors. The repurchase program does not obligate us to acquire any particular amount of common stock and may be modified or suspended at any time and could be terminated prior to completion. The

38

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 — Stockholders’ Equity  – (continued)

repurchase program will be funded with cash on hand or borrowings on our revolving credit facility. Any repurchased shares of common stock will be retained at our subsidiary level, subject to transfer to the parent company where they may be retired.

Pursuant to the stock repurchase program approved by our Board of Directors in May 2013, during the year ended June 30, 2014, we incurred $94.2 million to repurchase 3,700,463 shares of our common stock at a weighted average price per share, excluding fees, of $25.45 and during the year ended June 30, 2013, we incurred $72.7 million to repurchase 2,938,900 shares of our common stock at a weighted average price per share, excluding fees, of $24.70. As of June 30, 2014, $83.2 million remains available for repurchase under the share repurchase program.

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

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

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

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

Preferred Stock

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

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

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

Conversion of Preferred Stock

During the year ended June 30, 2014, we canceled and converted a total of 428 shares of our 5.625% Preferred Stock into a total of 4,288 shares of common stock using a conversion rate ranging from 10.0147 to 10.0579 common shares per preferred share and during the year ended June 30, 2013, we canceled and converted a total of 929 shares of our 5.625% Preferred Stock into a total of 9,183 shares of common stock using a conversion rate ranging from 9.8578 to 9.899 common shares per preferred share.

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.

39

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11 — Supplemental Cash Flow Information

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

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

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

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

Note 12 — Employee Benefit Plans

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

Performance Units

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

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

TSR Performance-Based Units.  For each TSR Performance-Based Unit, the executive will receive a cash payment equal to the grant date unit value of $5.00 multiplied by (a) the cumulative percentage change in the price per share of the Company’s common stock from the date on which the TSR Performance-Based Units were granted (the “Total Shareholder Return”) and (b) the TSR Unit Number Modifier.

In addition, the employee may have the opportunity to earn additional compensation based on the Company’s Total Shareholder Return at the end of the third Performance Period.

At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due employees will be settled in either common shares or cash. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable. Historically, we have settled all vesting awards in cash. The July 21, 2014 vesting of the July 21, 2013 and 2012 Performance Unit awards were settled 50% in common stock and future vesting of the Performance Units may be settled in stock at the discretion of our board of directors.

40

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans  – (continued)

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

	Year Ended June 30,
	2014		2013		2012
Restricted Stock Units	$	12,798	$	10,707	$	19,315
Performance Units		11,446		10,569		31,148
Total compensation expense recognized	$	24,244	$	21,276	$	50,463

As of June 30, 2014, we have 1,394,175 unvested Restricted Stock Units and 6,780,358 unvested Performance Based Units.

Stock Purchase Plan

Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of our common stock that have either been purchased by us on the open market or are newly issued by us. During the years ended June 30, 2014, 2013 and 2012, we issued 148,519 shares, 213,763 shares and 305,401 shares, respectively, under the 2008 Purchase Plan.

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period. The current offering period is from July 1, 2014 to December 31, 2014. We use the Black-Scholes Model to determine fair value, which incorporates assumptions to value stock-based awards. The shares issuable under the Employee Stock Purchase Plan are included in calculating diluted earnings per share, if dilutive. As of June 30, 2014 there was no unrecognized compensation. The compensation expense recognized and shares issued under the Employee Stock Purchase Plan were as follows (in thousands, except for shares):

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

Stock Options

In September 2008, our Board of Directors granted 300,000 stock options to certain officers of the Company. These options to purchase our common stock were granted with an exercise price of $17.50 per share. These options vested over a three year period and may be exercised any time prior to September 10, 2018. We utilized the Black-Scholes model to determine the fair value of these stock options. As of June 30, 2014, 100,000 of the vested options have been exercised and the remaining 200,000 vested options have not been exercised.

Defined Contribution Plans

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

	Year Ended June 30,
	2014		2013		2012
Profit Sharing Plan	$	4,833	$	2,738	$	3,014
401(k) Plan		3,395		3,381		3,195

41

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans  – (continued)

	Year Ended June 30,
	2014		2013		2012
Total contributions	$	8,228	$	6,119	$	6,209

Note 13 — Related Party Transactions

We have a 20% interest in EXXI M21K and account for this investment using the equity method. EXXI M21K is the guarantor of a $100 million line of credit entered into by M21K. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Form 10-K.

We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K for EP Energy Property acquisition estimated at $65 million and $1.8 million, respectively. For the LLOG Exploration acquisition, we guaranteed payment of asset retirement obligations by M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchase, we guaranteed payment of asset retirement obligation by M21K estimated at $18.6 million. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the year ended June 30, 2014 and 2013, we have received $3.1 million and $1.9 million, respectively, related to such guarantees.

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

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

42

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14 — Earnings per Share

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

	Year Ended June 30,
	2014		2013		2012
Net income	$	59,111	$	162,081	$	335,827
Preferred stock dividends		11,489		11,496		13,028
Induced conversion of preferred stock		—		—		6,068
Net income available for common stockholders	$	47,622	$	150,585	$	316,731
Weighted average shares outstanding for basic EPS		74,375		79,063		77,310
Add dilutive securities		70		8,200		9,898
Weighted average shares outstanding for diluted EPS		74,445		87,263		87,208
Earnings per share
Basic	$	0.64	$	1.90	$	4.10
Diluted	$	0.64	$	1.86	$	3.85

For the years ended June 30, 2014, 2013 and 2012, we had 8,336,700, 5,474 and 4,821, respectively, of common stock equivalents that were excluded from the diluted average shares due to an anti-dilutive effect.

Note 15 — Commitments and Contingencies

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

Litigation Related to the Merger

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

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

43

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 — Commitments and Contingencies  – (continued)

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

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

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

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

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

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

Guarantee.  EXXI M21K is the guarantor of a $100 million line of credit entered into by M21K. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Form 10-K. We have provided guarantees related to the payment of asset retirement obligations and other liabilities by M21K for the EP Energy, LLOG Exploration and Eugene Island 330 and South Marsh Island 128 properties acquisitions. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. See Note 13 — Related Party Transactions of Notes to Consolidated Financial Statements in this Form 10-K.

Drilling Rig Commitments.  The drilling rig commitments represent minimum future expenditures for drilling rig services. The expenditures for drilling rig services will exceed such minimum amounts to the extent we utilize the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract. As of June 30, 2014, we have entered into nine drilling rig commitments:

1) April 10, 2014 to October 27, 2014 at $54,448 per day.

2) January 1, 2014 to July 15, 2014 at $107,500 per day.

3) October 1, 2013 to September 1, 2014 at $125,000 per day.

4) March 10, 2014 to March 9, 2015 at $53,175 per day.

44

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 — Commitments and Contingencies  – (continued)

5) September 1, 2013 to August 31, 2014 at $140,000 per day.

6) February 15, 2014 to August 15, 2014 at $111,380 per day.

7) April 11, 2014 to September 15, 2014 at $112,000 per day.

8) July 1, 2014 to September 1, 2014 at $107,500 per day.

9) September 1, 2014 to October 1, 2014 at $107,500 per day.

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

Note 16 — Income Taxes

Our parent Company is a Bermuda company and it is generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure.

During the year ended June 30, 2009, we incurred a pre-tax impairment loss related to our oil and gas properties due to the steep decline in global energy prices over that same time period. This loss is not deductible for tax purposes until the impaired properties are depleted or disposed of. As a result of this impairment, we have reported cumulative losses and remain marginally in an overall loss position. Due to this previous loss position, coupled with volatility in energy prices (at the time) causing uncertainty as to operating results, we established a valuation allowance of $175.0 million during the year ended June 30, 2009. We have subsequently reduced this allowance by $152.5 million due principally to the reported pre-tax income in the subsequent years. This results in an ending valuation allowance of $22.5 million at June 30, 2014, which relates to certain State of Louisiana net operating loss carryovers that we do not currently believe, on a more-likely-than-not basis, are realizable due to our current focus on offshore operations. Management continues to monitor this situation closely, and the results from any change in judgment reflecting a change in the underlying facts will be reflected in the period of the factual change.

The amounts of income before income taxes attributable to U.S. and non-U.S. operations are as follows:

	Year Ended June 30,
	2014		2013		2012
	(In Thousands)
U.S. income	$	106,970	$	223,337	$	346,887
Non-U.S. income		9,230		25,377		27,586
Income before income taxes	$	116,200	$	248,714	$	374,473

45

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Income Taxes  – (continued)

The components of our income tax provision are as follows:

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

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

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

46

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Income Taxes  – (continued)

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below:

	June 30,
	2014			2013
	(In Thousands)
Deferred tax assets – current
Asset retirement obligation	$	44,182		$	—
Other		8,405			—
Total deferred tax assets – current		52,587			—
Deferred tax liabilities – current
Federal withholding obligation		—			(20,517	)
Deferred tax assets – non current
Asset retirement obligation		61,412			100,697
Tax loss carryforwards on U.S. operations		448,404			386,899
Accrued interest expense		79,636			65,418
Deferred interest expense under IRC Sec. 162(j)		—			28,721
Employee benefit plans		—			6,213
Deferred state taxes		22,494			22,494
Derivative instruments and other		12,163			—
Other		11,471			6,860
Total deferred tax assets – non current		635,580			617,302
Deferred tax liabilities
Derivative instruments and other		—			(10,193	)
Oil, natural gas properties and other property and equipment		(1,183,864	)		(628,554	)
Federal withholding obligation		(63,143	)		(34,983	)
Cancellation of debt		(9,680	)		(9,680	)
Employee benefit plans		(3,611	)		—
Tax partnership activity		(53,826	)		(52,202	)
Total deferred tax liabilities – non current		(1,314,124	)		(735,612	)
Valuation allowance		(22,494	)		(22,494	)
Net deferred tax liability	$	(648,451	)	$	(161,321	)
Reflected in the accompanying balance sheet as
Current deferred tax asset (liability)	$	52,587		$	(20,517	)
Non-current deferred tax liability	$	(701,038	)	$	(140,804	)

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

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

47

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Income Taxes  – (continued)

Section 382 of the Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an “ownership change” and Code Section 383 provides similar rules for other tax attributes, e.g., capital losses. In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation by more than 50 percentage points over a three year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382 determined by multiplying the value of the Company’s stock at the time of the ownership change by the applicable long-term tax exempt rate (ranging between approximately 2.7% and 3.3%). Any unused annual limitation may be carried over to subsequent years. The amount of the limitation may, under certain circumstances, be increased by the built-in gains held by the Company at the time of the ownership change that are recognized in the five year period after the change. The Company experienced an ownership change on June 20, 2008, and a second ownership change on November 3, 2010. EPL similarly experienced an ownership change in 2009 and upon its acquisition in 2014. Based upon the Company’s determination of its annual limitation related to this ownership change, management believes that Section 382 should not otherwise limit the Company’s ability to utilize its federal or state NOLs or other attribute carryforwards during their applicable carryforward periods. Management will continue to monitor the potential impact of Code Sections 382 and 383 in future periods with respect to NOL and other tax carryforwards and will reassess realization of these carryforwards periodically.

We have not recorded any reserves for uncertain tax positions. We have a gross unrecorded noncurrent deferred tax asset of $13.2 million representing a percentage depletion carryover resulting from the EPL acquisition.

We filed our initial tax returns for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 through 2013. The tax years ended June 30, 2011 through 2014 remain open to examination under the applicable statute of limitations in the U.S. in which the Company and its subsidiaries file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not begin to run until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law. On May 13, 2014, the U.S. Internal Revenue Service (“IRS”) notified the Company of their intent to examine the Company’s U.S. federal income tax return (Form 1120) for the year ended June 30, 2013. The resolution of unagreed tax issues cannot be predicted with absolute certainty, and differences between what has been recorded and the eventual outcomes may occur. The Company believes that it has adequately provided for income taxes and any related interest and penalties for all open tax years.

We have historically paid no significant US cash income taxes due to the election to expense intangible drilling costs and the presence of our NOLs. However, if current income trends continue, we could be responsible for making cash tax payments in fiscal 2015 from application of the alternative minimum tax (AMT) under current law. We presently do not expect to make any cash income tax payments during the upcoming fiscal year. If any such AMT payments were required, we believe that they would be recoverable against future regular income taxes due, with no expiration period. As such, we do not believe that any AMT payments would have a negative impact on earnings. We revise our ongoing estimated AMT obligation each quarter during the year.

We paid $3.6 million cash in U.S. withholding taxes during the year as a result of payments of interest on indebtedness and management fees to our Bermuda entities. These withholding taxes are presented as separate line items in the effective tax rate reconciliation and payments expected in the coming fiscal year are presented as a current federal withholding obligation in the balance sheet.

Note 17 — Concentrations of Credit Risk

Major Customers.  We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not

48

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Concentrations of Credit Risk  – (continued)

operate. The majority of our operated gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

Shell Trading Company (“Shell”) accounted for approximately 45%, 35% and 32% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 43%, 37% and 37% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. J.P. Morgan Ventures Energy Corporation accounted for 12% and 18% of our total oil and natural gas revenues during the years ended June 30, 2013 and 2012, respectively. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Shell or ExxonMobil curtailed their purchases.

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

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

Cash and Cash Equivalents.  We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. At times cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation.

Note 18 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

The carrying amounts approximate fair value for cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable due to the short-term nature or maturity of the instruments.

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Form 10-K.

The fair values of our stock based units are based on period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model is used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on TSR Performance-Based Units valuation.

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

49

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

• Level 1 — quoted prices in active markets for identical assets or liabilities.

• Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

• Level 3 — unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

During fiscal year 2014, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

	Level 1				Level 2
	As of June 30,				As of June 30,
	2014		2013		2014		2013
Assets:
Oil and natural gas derivatives					$	26,975	$	96,455
Liabilities:
Oil and natural gas derivatives					$	58,778	$	36,180
Restricted stock units	$	9,425	$	7,642
Time-based performance units		3,698		3,059
Total liabilities	$	13,123	$	10,701	$	58,778	$	36,180

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

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

50

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 19 — Prepayments and Accrued Liabilities

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

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

Note 20 — Subsequent Events

On July 16, 2014, our Board of Directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of our common stock. The quarterly dividend will be paid on September 12, 2014 to shareholders of record on August 29, 2014.

Note 21 — Selected Quarterly Financial Data — Unaudited

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

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

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ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Year Ended June 30, 2013
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter
Revenues	$	314,325	$	303,774	$	320,519	$	270,227
Operating income		111,747		99,870		93,537		56,651
Net income	$	62,053	$	40,436	$	41,332	$	18,260
Preferred stock dividends		2,873		2,873		2,874		2,876
Net income available for common stockholders	$	59,180	$	37,563	$	38,458	$	15,384
Net income per share attributable to common stockholders(1)
Basic	$	0.75	$	0.47	$	0.48	$	0.19
Diluted		0.72		0.46		0.47		0.19

(1) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

Note 22 — Supplementary Oil and Gas Information — Unaudited

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

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

Oil and natural gas property costs excluded from the amortization base represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs are transferred to proved properties as the properties are evaluated or over the life of the reservoir. The wells in progress will be transferred into the amortization base once the results of the drilling activities are known.

We excluded from the amortization base the following costs related to unevaluated property costs and major development projects (in thousands):

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

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the U.S. are based on evaluations prepared by our reservoir engineers and audited by NSAI. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the unweighted arithmetic

52

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise that those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and millions of cubic feet (“MMcf”) for each of the periods indicated were as follows:

	Oil (MBbls)			Natural Gas (MMcf)			Total (MBOE)
Proved reserves at June 30, 2011		77,206			236,316			116,592
Production		(11,172	)		(29,824	)		(16,143	)
Extensions and discoveries		11,444			27,821			16,081
Revisions of previous estimates		9,098			(23,281	)		5,217
Reclassification of proved undeveloped		(1,783	)		(2,042	)		(2,123	)
Proved reserves at June 30, 2012		84,793			208,990			119,624
Production		(10,318	)		(32,354	)		(15,710	)
Extensions and discoveries		40,690			40,714			47,476
Revisions of previous estimates		14,380			7,903			15,697
Reclassification of proved undeveloped		(1,123	)		(1,755	)		(1,416	)
Purchases of reserves		5,225			45,623			12,829
Proved reserves at June 30, 2013		133,647			269,121			178,500
Production		(10,978	)		(32,754	)		(16,437	)
Extensions and discoveries		17,141			19,703			20,424
Revisions of previous estimates		(3,567	)		(29,822	)		(8,537	)
Sales of reserves		(4,159	)		(3,378	)		(4,722	)
Purchases of reserves		53,305			141,986			76,970
Proved reserves at June 30, 2014		185,389			364,856			246,198
Proved developed reserves
June 30, 2011		59,234			134,024			81,572
June 30, 2012		63,308			110,310			81,693
June 30, 2013		80,223			175,623			109,493
June 30, 2014		112,789			222,916			149,942
Proved undeveloped reserves
June 30, 2011		17,972			102,292			35,020
June 30, 2012		21,485			98,680			37,931
June 30, 2013		53,424			93,498			69,007
June 30, 2014		72,600			141,940			96,256

53

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

• Acquisitions of 52.3 MMBOE, primarily in the EPL Acquisition.

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

Offset by:

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

• Divestiture of 4.7 MMBOE, and

• Production of 16.4 MMBOE.

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

• Acquisitions of 24.6 MMBOE, primarily in the EPL Acquisition.

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

Offset by

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

• Conversion of 6.6 MMBOE from proved undeveloped to proved developed reserves.

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

We update and approve our reserves development plan on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total PUD reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors; including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves. As scheduled in our long range plan, all of our proved undeveloped locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our report, with the exception of two. They are locations to be sidetracked from existing wellbores which are still producing economically thus cannot be drilled until the proved developed producing zones deplete.

Standardized Measure of Discounted Future Net Cash Flows

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

54

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

12-month period ending on June 30, 2014). The report forecasts crude oil and NGL production separately. The average realized adjusted product prices weighted by production over the remaining lives of the properties, used to determine future net revenues were $103.80 per barrel of oil and $42.10 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. The $103.80 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $96.75 per barrel (differential of $7.05 per barrel).

For natural gas, the average Henry Hub price used was $4.10 per MMBtu, prior to adjustments for energy content, transportation fees, and regional price differentials (calculated using the unweighted average first-day-of-the-month Henry Hub spot price). The average adjusted realized natural gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $4.14 per Mcf after adjusting for energy content, transportation fees, and regional price differentials.

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2014, 2013 and 2012 are as follows (in thousands):

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

Changes in Standardized Measure of Discounted Future Net Cash Flows

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

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

55

ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 23 — Supplemental Guarantor Information

Our indirect, 100%-owned subsidiary, EGC, issued $650 million of its 6.875% Senior Notes due 2024 on May 27, 2014, $500 million of its 7.5% Senior Notes due 2021 on September 26, 2013, $750 million of its 9.25% Senior Notes due 2017 on December 17, 2010 and $250 million of its 7.75% Senior Notes due 2019 on February 25, 2011. 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 above 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 requires the issuer and guarantors to file separate financial statements. The Company meets the conditions in Rule 3-10 to report information about the assets, results of operations and comprehensive income (loss) and cash flows of the parent, subsidiary issuer and subsidiary guarantors using an alternative approach, which is to include in a footnote to the parent company’s financial statements condensed consolidating financial information for the same periods as those presented for the parent company 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, the 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.

56

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING BALANCE SHEET
(In Thousands)

	June 30, 2014
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	135,703		$	3,723		$	—	$	6,380		$	—		$	145,806
Accounts receivable
Oil and natural gas sales								127,773		50,990			(11,688	)		167,075
Joint interest billings					1,833					11,065						12,898
Insurance and other		10			3,452			517		1,460			(1	)		5,438
Prepaid expenses and other current assets		230			27,705			350		44,245						72,530
Deferred income taxes					27,424					25,163						52,587
Derivative financial instruments					1,425											1,425
Total Current Assets		135,943			65,562			128,640		139,303			(11,689	)		457,759
Property and Equipment
Oil and natural gas properties								3,324,923		3,197,765			1,914			6,524,602
Other property and equipment										19,760						19,760
Total Property and Equipment, net		—			—			3,324,923		3,217,525			1,914			6,544,362
Other Assets
Goodwill										327,235						327,235
Derivative financial instruments					3,035											3,035
Equity investments		1,744,908			2,969,070					2,110,608			(6,783,943	)		40,643
Intercompany receivables		102,489			1,627,931					60,562			(1,790,982	)		—
Restricted cash								325		6,025						6,350
Other assets and debt issuance costs, net		178,299			42,155					7,940			(171,000	)		57,394
Total Other Assets		2,025,696			4,642,191			325		2,512,370			(8,745,925	)		434,657
Total Assets	$	2,161,639		$	4,707,753		$	3,453,888	$	5,869,198		$	(8,755,700	)	$	7,436,778
LIABILITIES
Current Liabilities
Accounts payable	$	—		$	64,533		$	150,909	$	212,157		$	(11,881	)	$	415,718
Accrued liabilities		1,640			12,501			28,750		154,587			(63,952	)		133,526
Notes payable					21,967											21,967
Deferred income taxes		19,185											(19,185	)		—
Asset retirement obligations								39,819		39,830						79,649
Derivative financial instruments					5,517					26,440						31,957
Current maturities of long-term debt					14,093					927						15,020
Total Current Liabilities		20,825			118,611			219,478		433,941			(95,018	)		697,837
Long-term debt, less current maturities		342,986			2,305,906					1,266,732			(171,000	)		3,744,624
Deferred income taxes					211,055					470,798			19,185			701,038
Asset retirement obligations					49			247,272		232,864						480,185
Derivative financial instruments					2,166					2,140						4,306
Intercompany payables								1,736,240					(1,736,240	)		—
Other liabilities										10,958						10,958
Total Liabilities		363,811			2,637,787			2,202,990		2,417,433			(1,983,073	)		5,638,948
Stockholders’ Equity
Preferred stock
7.25% Convertible perpetual preferred stock																—
5.625% Convertible perpetual preferred stock		1														1
Common stock		468			1					10			(11	)		468
Additional paid-in capital		1,837,462			2,092,439			273,129		3,580,004			(5,945,572	)		1,837,462
Retained earnings (accumulated deficit)		(19,628	)		(2,040	)		977,769		(101,521	)		(874,206	)		(19,626	)
Accumulated other comprehensive (loss) income		(20,475	)		(20,434	)				(26,728	)		47,162			(20,475	)
Total Stockholders’ Equity		1,797,828			2,069,966			1,250,898		3,451,765			(6,772,627			1,797,830
Total Liabilities and Stockholders’ Equity	$	2,161,639		$	4,707,753		$	3,453,888	$	5,869,198		$	(8,755,700	)	$	7,436,778

57

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING BALANCE SHEET
(In Thousands)

	June 30, 2013
	EXXI Bermuda Parent			EGC Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,334		$	—	$	—		$	137		$	(1,471	)	$	—
Accounts receivable
Oil and natural gas sales							150,007						(17,486	)		132,521
Joint interest billings					9,505											9,505
Insurance and other					6,031		495			219						6,745
Prepaid expenses and other current assets		235			47,492		372			2,638			1			50,738
Derivative financial instruments					38,389											38,389
Total Current Assets		1,569			101,417		150,874			2,994			(18,956	)		237,898
Property and Equipment
Oil and natural gas properties					16,553		3,272,952									3,289,505
Other property and equipment										17,003						17,003
Total Property and Equipment, net		—			16,553		3,272,952			17,003			—			3,306,508
Other Assets
Derivative financial instruments					21,926											21,926
Equity investments		1,259,247			1,066,803					1,544,751			(3,858,002	)		12,799
Intercompany receivables		95,627			1,904,655					56,715			(2,056,997	)		—
Deferred income taxes										29,884			(29,884	)		—
Other assets and debt issuance costs, net		171,000			24,791					7,789			(171,000	)		32,580
Total Other Assets		1,525,874			3,018,175		—			1,639,139			(6,115,883	)		67,305
Total Assets	$	1,527,443		$	3,136,145	$	3,423,826		$	1,659,136		$	(6,134,839	)	$	3,611,711
LIABILITIES
Current Liabilities
Accounts payable	$	—		$	104,263	$	133,045		$	1,258		$	(18,956	)	$	219,610
Accrued liabilities		479			25,001		30,393			105,598			(56,279	)		105,192
Notes payable		175			22,349											22,524
Deferred income taxes										20,517						20,517
Asset retirement obligations							29,500									29,500
Derivative financial instruments					40											40
Current maturities of long-term debt					18,838					716						19,554
Total Current Liabilities		654			170,491		192,938			128,089			(75,235	)		416,937
Long-term debt, less current maturities		—			1,279,843					241,648			(171,000	)		1,350,491
Deferred income taxes		16,883			153,805								(29,884	)		140,804
Asset retirement obligations					50		258,268									258,318
Intercompany payables							1,913,195						(1,913,195	)		—
Other liabilities										7,915						7,915
Total Liabilities		17,537			1,604,189		2,364,401			377,652			(2,189,314	)		2,174,465
Stockholders’ Equity
Preferred stock
7.25% Convertible perpetual preferred stock																—
5.625% Convertible perpetual preferred stock		1														1
Common stock		396			1											397
Additional paid-in capital		1,512,310			1,426,351		369,195			1,370,648			(3,166,193	)		1,512,311
Retained earnings (accumulated deficit)		(29,352	)		79,304		690,231			(43,052	)		(726,483	)		(29,352	)
Accumulated other comprehensive (loss) income		26,551			26,300		(1	)		26,551			(52,849	)		26,552
Treasury stock										(72,663	)					(72,663	)
Total Stockholders’ Equity		1,509,906			1,531,956		1,059,425			1,281,484			(3,945,525	)		1,437,246
Total Liabilities and Stockholders’ Equity	$	1,527,443		$	3,136,145	$	3,423,826		$	1,659,136		$	(6,134,839	)	$	3,611,711

58

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	For the Year Ended June 30, 2014
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
Revenues
Crude oil sales	$	—		$	(11,525	)	$	1,046,263		$	56,485		$	—		$	1,091,223
Natural gas sales					3,710			132,134			3,658						139,502
Total Revenues		—			(7,815	)		1,178,397			60,143			—			1,230,725
Costs and Expenses
Lease operating					(325	)		348,027			18,045						365,747
Production taxes					51			4,716			660						5,427
Gathering and transportation								23,532									23,532
Depreciation, depletion and amortization								399,086			26,340			(2,107	)		423,319
Accretion of asset retirement obligations								28,161			2,022						30,183
General and administrative expense		7,380			1,134			81,380			6,508						96,402
Loss (gain) on derivative financial instruments					5,704												5,704
Total Costs and Expenses		7,380			6,564			884,902			53,575			(2,107	)		950,314
Operating Income (Loss)		(7,380	)		(14,379	)		293,495			6,568			2,107			280,411
Other Income (Expense)
Income (loss) from equity method investees		66,995			296,279						92,191			(460,246	)		(4,781	)
Other income – net		19,923			1,954						17,808			(36,387	)		3,298
Interest expense		(14,485	)		(138,336	)		(5,957	)		(40,337	)		36,387			(162,728	)
Total Other Income (Expense)		72,433			159,897			(5,957	)		69,662			(460,246	)		(164,211	)
Income (Loss) Before Income Taxes		65,053			145,518			287,538			76,230			(458,139	)		116,200
Income Tax Expense		5,942			48,546						2,601						57,089
Net Income (Loss)		59,111			96,972			287,538			73,629			(458,139	)		59,111
Preferred Stock Dividends		11,489												—			11,489
Net Income (Loss) Available for Common Stockholders	$	47,622		$	96,972		$	287,538		$	73,629		$	(458,139	)	$	47,622
Comprehensive Income (Loss)
Net Income (Loss)	$	59,111		$	96,972		$	287,538		$	73,629		$	(458,139	)	$	59,111
Other Comprehensive Income (Loss)		(47,027	)		(38,523	)					(8,504	)		47,027			(47,027	)
Comprehensive Income (Loss)	$	12,084		$	58,449		$	287,538		$	65,125		$	(411,112	)	$	12,084

59

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	For the Year Ended June 30, 2013
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
Revenues
Crude oil sales	$	—		$	13,295		$	1,067,687		$	—		$	—		$	1,080,982
Natural gas sales					15,110			112,753									127,863
Total Revenues		—			28,405			1,180,440			—			—			1,208,845
Costs and Expenses
Lease operating					(3,249	)		340,412									337,163
Production taxes					(658	)		5,904									5,246
Gathering and transportation								24,168									24,168
Depreciation, depletion and amortization								372,252			3,972						376,224
Accretion of asset retirement obligations								30,885									30,885
General and administrative expense		7,439			2,820			61,089			250						71,598
Loss (gain) on derivative financial instruments					1,915						(159	)					1,756
Total Costs and Expenses		7,439			828			834,710			4,063			—			847,040
Operating Income (Loss)		(7,439	)		27,577			345,730			(4,063	)		—			361,805
Other Income (Expense)
Income (loss) from equity method investees		156,516			333,039						176,979			(672,931	)		(6,397	)
Other income – net		18,584			1,849			12			17,833			(36,313	)		1,965
Interest expense		(5	)		(93,200	)		(15,160	)		(36,607	)		36,313			(108,659	)
Total Other Income (Expense)		175,095			241,688			(15,148	)		158,205			(672,931	)		(113,091	)
Income (Loss) Before Income Taxes		167,656			269,265			330,582			154,142			(672,931	)		248,714
Income Tax Expense (Benefit)		5,575			85,889						(4,831	)					86,633
Net Income (Loss)		162,081			183,376			330,582			158,973			(672,931	)		162,081
Preferred Stock Dividends		11,496															11,496
Net Income (Loss) Available for Common Stockholders	$	150,585		$	183,376		$	330,582		$	158,973		$	(672,931	)	$	150,585
Comprehensive Income (Loss)
Net Income (Loss)	$	162,081		$	183,376		$	330,582		$	158,973		$	(672,931	)	$	162,081
Other Comprehensive Income (Loss)		(31,051	)		(32,985	)					1,934			31,051			(31,051	)
Comprehensive Income (Loss)	$	131,030		$	150,391		$	330,582		$	160,907		$	(641,880	)	$	131,030

60

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	For the Year Ended June 30, 2012
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
Revenues
Crude oil sales	$	—		$	645		$	1,185,986	$	—		$	—		$	1,186,631
Natural gas sales					29,871			86,901								116,772
Total Revenues		—			30,516			1,272,887		—			—			1,303,403
Costs and Expenses
Lease operating					(343	)		311,158								310,815
Production taxes					4			7,257								7,261
Gathering and transportation								16,371								16,371
Depreciation, depletion and amortization								364,281		3,182						367,463
Accretion of asset retirement obligations								39,161								39,161
General and administrative expense		6,990			3,476			75,603		207						86,276
Loss (gain) on derivative financial instruments					(7,261	)				33						(7,228	)
Total Costs and Expenses		6,990			(4,124	)		813,831		3,422			—			820,119
Operating Income (Loss)		(6,990	)		34,640			459,056		(3,422	)		—			483,284
Other Income (Expense)
Income (loss) from equity method investees		331,110			459,057					315,146			(1,105,313	)		—
Other income – net		16,722			1,191			1		17,828			(35,671	)		71
Interest expense					(108,731	)				(35,822	)		35,671			(108,882	)
Total Other Income (Expense)		347,832			351,517			1		297,152			(1,105,313	)		(108,811	)
Income (Loss) Before Income Taxes		340,842			386,157			459,057		293,730			(1,105,313	)		374,473
Income Tax Expense (Benefit)		5,015			71,010					(37,379	)					38,646
Net Income (Loss)		335,827			315,147			459,057		331,109			(1,105,313	)		335,827
Induced Conversion of Preferred Stock		6,068														6,068
Preferred Stock Dividends		13,028														13,028
Net Income (Loss) Available for Common Stockholders		316,731			315,147			459,057		331,109			(1,105,313	)		316,731
Comprehensive Income (Loss)
Net Income (Loss)	$	335,827		$	315,147		$	459,057	$	331,109		$	(1,105,313	)	$	335,827
Other Comprehensive Income (Loss), net		126,087			126,087								(126,087	)		126,087
Comprehensive Income (Loss)	$	461,914		$	441,234		$	459,057	$	331,109		$	(1,231,400	)	$	461,914

61

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

	For the Year Ended June 30, 2014
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
Cash Flows From Operating Activities
Net income (Loss)	$	59,111		$	96,972		$	287,538		$	73,629		$	(458,139	)	$	59,111
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization								399,086			26,340			(2,107	)		423,319
Deferred income tax expense (benefit)		2,301			48,546						2,601						53,448
Change in derivative financial instruments
Other – net					(1,793	)											(1,793	)
Accretion of asset retirement obligations								28,161			2,022						30,183
Loss (income) from equity method investees		(66,995	)		(296,279	)					(92,191	)		460,246			4,781
Amortization and write-off of debt issuance costs and other		7,219			6,555												13,774
Stock-based compensation		6,712												(1	)		6,711
Changes in operating assets and liabilities
Accounts receivable		(10	)		22,708			22,212			18,372			1			63,283
Prepaid expenses and other current assets		(18	)		19,746			23			(13,733	)		1			6,019
Settlement of asset retirement obligations								(57,391	)								(57,391	)
Accounts payable and accrued liabilities		(5,852	)		87,745			(256,799	)		1,284,956			(1,166,035	)		(55,985	)
Net Cash Provided by (Used in) Operating Activities		2,468			(15,800	)		422,830			1,301,996			(1,166,034	)		545,460
Cash Flows from Investing Activities
Acquisitions, net of cash acquired								(37,657	)		(811,984	)					(849,641	)
Capital expenditures					16,746			(513,096	)		(292,326	)					(788,676	)
Insurance payments received								1,983									1,983
Change in equity method investments											(34,294	)					(34,294	)
Proceeds from the sale of properties								126,265									126,265
Intercompany investment		(185,568	)		(979,420	)					(2,570	)		1,167,558			—
Transfer to restricted cash								(325	)								(325	)
Other											113						113
Net Cash Provided by (Used in) Investing Activities		(185,568	)		(962,674	)		(422,830	)		(1,141,061	)		1,167,558			(1,544,575	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		3,994															3,994
Discount on convertible debt allocated to additional paid-in capital		63,432															63,432
Repurchase of company common stock		(30,824	)								(153,439	)					(184,263	)
Dividends to shareholders – common		(34,680	)														(34,680	)
Dividends to shareholders – preferred		(11,489	)														(11,489	)
Proceeds from long-term debt		336,568			3,085,145						(840	)					3,420,873
Payments on long-term debt		—			(2,079,072	)					(413	)					(2,079,485	)
Debt issuance costs		(9,585	)		(23,876	)											(33,461	)
Other		53												(53	)		—
Net Cash Provided by (Used in) Financing Activities		317,469			982,197			—			(154,692	)		(53	)		1,144,921
Net Increase in Cash and Cash Equivalents		134,369			3,723			—			6,243			1,471			145,806
Cash and Cash Equivalents, beginning of year		1,334			—			—			137			(1,471	)		—
Cash and Cash Equivalents, end of year	$	135,703		$	3,723		$	—		$	6,380		$	—		$	145,806

62

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

	For the Year Ended June 30, 2013
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
Cash Flows From Operating Activities
Net income (Loss)	$	162,081		$	183,376		$	330,582		$	158,973		$	(672,931	)	$	162,081
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization								372,252			3,972						376,224
Deferred income tax expense		(7,297	)		85,889						(4,831	)					73,761
Change in derivative financial instruments
Proceeds from sale of derivative instruments					635						125						760
Other – net					(27,357	)					(159	)					(27,516	)
Accretion of asset retirement obligations								30,885									30,885
Loss (income) from equity method investees		(156,516	)		(333,039	)					(176,979	)		672,931			6,397
Amortization and write-off of debt issuance costs and other					6,857						41						6,898
Stock-based compensation		3,504												1			3,505
Changes in operating assets and liabilities
Accounts receivable					14,422			(13,156	)		424						1,690
Prepaid expenses and other current assets		8,772			2,865			760			103			(1	)		12,499
Settlement of asset retirement obligations								(41,939	)								(41,939	)
Accounts payable and accrued liabilities		15,437			(284,637	)		269,560			79,024			(46,481	)		32,903
Net Cash Provided by (Used in) Operating Activities		25,981			(350,989	)		948,944			60,693			(46,481	)		638,148
Cash Flows from Investing Activities
Acquisitions, net of cash acquired								(161,164	)								(161,164	)
Capital expenditures					(17,144	)		(787,774	)		(11,187	)					(816,105	)
Change in equity method investments											(16,693	)					(16,693	)
Intercompany investment		(4,010	)								(41,000	)		45,010			—
Other								(6	)		(35	)					(41	)
Net Cash Provided by (Used in) Investing Activities		(4,010	)		(17,144	)		(948,944	)		(68,915	)		45,010			(994,003	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		7,021									—						7,021
Repurchase of company common stock											(58,666	)					(58,666	)
Dividends to shareholders – common		(25,992	)								—						(25,992	)
Dividends to shareholders – preferred		(11,496	)								—						(11,496	)
Proceeds from long-term debt					1,571,061						5,490						1,576,551
Payments on long-term debt					(1,243,545	)					(303	)					(1,243,848	)
Debt issuance costs					(4,777	)					(28	)					(4,805	)
Other											3						3
Net Cash Provided by (Used in) Financing Activities		(30,467	)		322,739			—			(53,504	)		—			238,768
Net Decrease in Cash and Cash Equivalents		(8,496	)		(45,394	)		—			(61,726	)		(1,471	)		(117,087	)
Cash and Cash Equivalents, beginning of year		9,830			45,394			—			61,863			—			117,087
Cash and Cash Equivalents, end of year	$	1,334		$	—		$	—		$	137		$	(1,471	)	$	—

63

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

	For the Year Ended June 30, 2012
	EXXI Bermuda Parent			EGC Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
Cash Flows From Operating Activities
Net income (Loss)	$	335,827		$	315,147		$	459,057		$	331,109		$	(1,105,313	)	$	335,827
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization								364,281			3,182						367,463
Deferred income tax expense		5,015			71,011						(37,230	)					38,796
Change in derivative financial instruments
Proceeds from sale of derivative instruments					66,522												66,522
Other – net					(52,155	)											(52,155	)
Accretion of asset retirement obligations					—			39,161									39,161
Loss (income) from equity method investees		(331,110	)		(459,057	)					(315,146	)		1,105,313			—
Amortization and write-off of debt issuance costs and other					7,468						91						7,559
Stock-based compensation		11,702									58						11,760
Changes in operating assets and liabilities
Accounts receivable					(17,406	)		12,984			(573	)					(4,995	)
Prepaid expenses and other current assets		(8,703	)		(5,565	)		892			(2,514	)					(15,890	)
Settlement of asset retirement obligations								(14,990	)								(14,990	)
Accounts payable and accrued liabilities		(15,919	)		232,527			(298,228	)		93,157			(5,081	)		6,456
Net Cash Provided by (Used in) Operating Activities		(3,188	)		158,492			563,157			72,134			(5,081	)		785,514
Cash Flows from Investing Activities
Acquisitions, net of cash acquired								(6,401	)								(6,401	)
Capital expenditures								(565,978	)		(4,692	)					(570,670	)
Insurance payments received								6,472									6,472
Change in equity method investments											(2,201	)					(2,201	)
Proceeds from the sale of properties								2,750									2,750
Intercompany investment and other		(1,000	)								(3,624	)		5,081			457
Net Cash Provided by (Used in) Investing Activities		(1,000	)		—			(563,157	)		(10,517	)		5,081			(569,593	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		9,839															9,839
Discount on convertible debt allocated to additional paid-in capital																	—
Conversion of preferred stock to common stock		(6,040	)														(6,040	)
Dividends to shareholders – preferred		(18,682	)														(18,682	)
Proceeds from long-term debt					896,717												896,717
Payments on long-term debt					(1,008,300	)											(1,008,300	)
Other		212			(859	)					(128	)					(775	)
Net Cash Provided by (Used in) Financing Activities		(14,671	)		(112,442	)		—			(128	)		—			(127,241	)
Net Increase (Decrease) in Cash and Cash Equivalents		(18,859	)		46,050			—			61,489			—			88,680
Cash and Cash Equivalents, beginning of year		28,689			(656	)		—			374			—			28,407
Cash and Cash Equivalents, end of year	$	9,830		$	45,394		$	—		$	61,863		$	—		$	117,087

64

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 23 day of December 2014.

ENERGY XXI LTD

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

John D. Schiller, Jr.
Chairman of the Board, President and
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ JOHN D. SCHILLER, JR. John D. Schiller, Jr.	Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)	December 23, 2014
/s/ BRUCE W. BUSMIRE Bruce W. Busmire	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	December 23, 2014
/s/ WILLIAM COLVIN William Colvin	Director	December 23, 2014
/s/ PAUL DAVISON Paul Davison	Director	December 23, 2014
/s/ CORNELIUS DUPRÉ II Cornelius Dupré II	Director	December 23, 2014
/s/ HILL A. FEINBERG Hill A Feinberg	Director	December 23, 2014
/s/ KEVIN S. FLANNERY Kevin S. Flannery	Director	December 23, 2014
/s/ SCOTT A. GRIFFITHS Scott A. Griffiths	Director	December 23, 2014
/s/ NORMAN LOUIE Norman Louie	Director	December 23, 2014
/s/ JAMES LACHANCE James LaChance	Director	December 23, 2014

65

EXHIBIT INDEX

Exhibit Number	Description	Originally Filed as Exhibit	File Number
2.1	Agreement and Plan of Merger among Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., Clyde Merger Sub, Inc. and EPL Oil & Gas, Inc., dated as of March 12, 2014	Included as Annex A to the Registration Statement on Form S-4 filed on April 1, 2014	333-194942
2.2	Amendment No. 1 to Agreement and Plan of Merger among Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., Clyde Merger Sub, Inc. and EPL Oil & Gas, Inc., dated as of April 15, 2014	2.2 to the Company Form S-4/A filed on April 15, 2014	333-194942
3.1	Altered Memorandum of Association of Energy XXI (Bermuda) Limited	3.1 to the Company’s Form 8-K filed on November 9, 2011	001-33628
3.2	Bye-Laws of Energy XXI (Bermuda) Limited	3.2 to the Company’s Form 8-K filed on November 9, 2011	001-33628
4.1	Investor Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) Limited, Sunrise Securities Corp. and Collins Steward Limited	4.1 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
4.2	Registration Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) and the investors named therein	4.2 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
4.3	Indenture related to the 9.25% Senior Notes due 2017, dated December 17, 2010, by and among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as trustee	4.1 to Form 8-K filed on December 22, 2010	001-33628
4.4	Indenture related to the 7.75% Senior Notes due 2019, dated as of February 25, 2011 among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee	4.1 to Form 8-K filed on February 28, 2011	001-33628
4.5	Indenture related to the 7.50% Senior Notes due 2021, dated as of September 26, 2013 among Energy XXI Gulf Coast, Inc., Energy XXI (Bermuda) Limited, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee	4.1 to the Company’s Form 8-K filed on September 26, 2013	001-33628

66

Exhibit Number	Description	Originally Filed as Exhibit	File Number
4.6	Registration Rights Agreement dated as of September 26, 2013 among Energy XXI Gulf Coast, Inc., Citigroup Global Markets Inc. and RBS Securities Inc., as representatives of the Initial Purchasers, Energy XXI (Bermuda) Limited and the Guarantors named therein	4.2 to the Company’s Form 8-K filed on September 26, 2013	001-33628
4.7	Indenture related to the 3.0% Senior Convertible Notes due 2018, dated November 22, 2013, by and between Energy XXI (Bermuda) Limited and Wells Fargo Bank, National Association, as trustee (including the form of 3.0% Senior Convertible Note due 2018)	4.1 to the Company’s Form 8-K filed on November 22, 2013	001-33628
4.8	Indenture related to the 6.875% Senior Notes due 2024, dated as of May 27, 2014, by and among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee	4.1 to the Company’s Form 8-K filed on May 29, 2014	001-33628
4.9	Registration Rights Agreement dated as of May 27, 2014 among Energy XXI Gulf Coast, Inc., Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as representatives of the Initial Purchasers and the Guarantors named therein	4.2 to the Company’s Form 8-K filed on May 29, 2014	001-33628
4.10	Indenture related to the 8.25% Senior Notes due 2018, dated as of February 14, 2011, by and among Energy Partners, Ltd., as Issuer, the Guarantors named therein and U.S. Bank National Association, as Trustee	4.1 to EPL Oil & Gas, Inc. Form 8-K filed on February 15, 2011	001-16179
4.11	Supplemental Indenture related to the 8.25% Senior Notes due 2018, dated as of March 14, 2011, by and among Anglo-Suisse Offshore Pipeline Partners, LLC, as a Guarantor, Energy Partners, Ltd., as Issuer, the other Guarantors named therein and U.S. Bank National Association, as Trustee	4.2 to EPL Oil & Gas, Inc. Form S-4 filed on August 14, 2011	333-175567
4.12	Second Supplemental Indenture related to the 8.25% Senior Notes due 2018, dated October 31, 2012, by and among Hilcorp Energy GOM, LLC, as a Guarantor, EPL Oil & Gas, Inc., as Issuer, the other Guarantors named therein, and U.S. Bank National Association, as Trustee	4.3 to EPL Oil & Gas, Inc. Form 10-K filed on March 7, 2013	001-16179

67

Exhibit Number	Description	Originally Filed as Exhibit	File Number
4.13	Indenture related to the 8.25% Senior Notes due 2018, dated October 25, 2012, by and among EPL Oil & Gas, Inc., the Guarantors named therein and U.S. Bank National Association, as Trustee	4.1 to EPL Oil & Gas, Inc. Form 8-K filed on October 30, 2012	001-16179
4.14	First Supplemental Indenture related to the 8.25% Senior Notes due 2018, dated October 31, 2012, by and among Hilcorp Energy GOM, LLC, as a Guarantor, EPL Oil & Gas, Inc., as Issuer, the other Guarantors named therein, and U.S. Bank National Association, as Trustee	4.5 to EPL Oil & Gas, Inc. Form 10-K filed on March 7, 2013	001-16179
4.15	Third Supplemental Indenture related to the 8.25% Senior Notes due 2018, by and among EPL Oil & Gas, Inc., the other Guarantors named therein and U.S. Bank National Association, as Trustee, dated April 18, 2014	4.1 to EPL Oil & Gas, Inc. Form 8-K filed on April 21, 2014	001-16179
10.1†	Form of Restricted Stock Grant Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.6 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.2†	Form of Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.7 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.3	Letter Agreement dated September 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P.	10.12 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007	333-145639
10.4†	Form of Notice of Grant of Stock Option together with Form of Stock Option Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.25 to Form 10-K filed on September 11, 2008	001-33628
10.5†	Energy XXI Services, LLC Directors’ Deferred Compensation Plan	10.1 to Form 8-K filed on September 10, 2008	001-33628
10.6†	Employment Agreement of John D. Schiller, Jr., effective September 10, 2008	10.1 to Form 8-K filed on September 11, 2008	001-33628
10.7†	Separation Agreement of Steve Weyel, effective August 25, 2010	10.1 to Form 8-K filed on August 23, 2010	001-33628
10.8†	Employment Agreement of David West Griffin, effective September 10, 2008	10.3 to Form 8-K filed on September 11, 2008	001-33628

68

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.9†	Form of Indemnification Agreement between Energy XXI (Bermuda) Limited and Indemnitees	10.1 to Form 8-K filed on November 5, 2008	001-33628
10.10†	Form of Indemnification Agreement Between Company Subsidiaries and Indemnitees	10.2 to Form 8-K filed on November 5, 2008	001-33628
10.11†	Energy XXI Services, LLC Employee Stock Purchase Plan	10.1 to Form 8-K filed on November 5, 2008	001-33628
10.12†	Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan	4.2 to Form S-8 filed on June 10, 2009	333-159868
10.13†	Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Restricted Stock Unit Awards Agreement	10.20 to Form 10-K filed on August 9, 2012	001-33628
10.14**†	Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Performance Unit Awards Agreement	10.14 to the Company’s Form 10-K filed on August 25, 2014	001-33628
10.15**†	Energy XXI Services, LLC, Employee Severance Plan (Amended and Restated August 1, 2014)	10.15 to the Company’s Form 10-K filed on August 25, 2014	001-33628
10.16†	Amended and Restated 2006 Long-Term Incentive Plan of Energy XXI Services, LLC	10.1 to Form S-8 filed on December 15, 2009	333-163736
10.17	Second Amended and Restated First Lien Credit Agreement, dated as of May 5, 2011, among Energy XXI Gulf Coast, Inc., the various financial institutions and other parties from time to time parties thereto, as lenders, The Royal Bank of Scotland plc, as administrative Agent, and the other persons parties thereto in the capacities specified therein	10.1 to Form 8-K filed on May 6, 2011	001-33628
10.18	First Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 4, 2011	10.1 to Form 8-K filed on October 4, 2011	001-33628
10.19	Second Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 24, 2012	10.1 to Form 8-K filed on May 25, 2012	001-33628
10.20	Third Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 19, 2012	10.1 to Form 8-K filed on October 15, 2012	001-33628
10.21	Fourth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of April 9, 2013	10.1 to Form 8-K filed on April 10, 2013	001-33628
10.22	Fifth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 1, 2013	10.1 to Form 8-K filed on May 6, 2013	001-33628

69

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.23	Sixth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of September 27, 2013	10.1 to the Company’s Form 8-K filed on September 27, 2013	001-33628
10.24	Seventh Amendment to Second Amended and Restated First Lien Credit Agreement dated as of April 7, 2014	10.1 to the Company’s Form 8-K filed on April 7, 2014	001-33628
10.25**	Eighth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 23, 2014	10.25 to the Company’s Form 10-K filed on August 25, 2014	001-33628
10.26**	Waiver to Second Amended and Restated First Lien Credit Agreement, dated as of August 22, 2014	10.26 to the Company’s Form 10-K filed on August 25, 2014	001-33628
10.27	Energy XXI Services, LLC Restoration Plan Amended and Restated effective January 1, 2013	10.1 to Form 10-Q filed on January 31, 2013	001-33628
10.28	Purchase Agreement, dated September 23, 2013, by and between Energy XXI Gulf Coast, Inc., Citigroup Global Markets Inc. and RBS Securities Inc., as representatives of the Initial Purchasers, Energy XXI (Bermuda) Limited and the Guarantors named therein	10.1 to the Company’s Form 8-K filed on September 26, 2013	001-33628
10.29	Purchase Agreement, dated as of November 18, 2013, among Energy XXI (Bermuda) Limited, Barclays Capital Inc., Citigroup Global Markets Inc., Wells Fargo Securities, LLC and the other initial purchasers named therein.	10.1 to the Company’s Form 8-K filed on November 22, 2013	001-33628
10.30	Form of Energy XXI Voting Agreement, dated as of March 12, 2014	10.1 to the Company’s Form 8-K filed on March 13, 2013	001-33628
10.31	Form of EPL Oil & Gas Voting Agreement, dated as of March 12, 2014
10.32	Consulting Agreement, dated as of April 15, 2014, by and between Energy XXI (Bermuda) Limited and Gary C. Hanna	10.28 to Amendment No. 1 to the Company’s Registration Statement on Form S-4 filed on April 15, 2014	333-194942
10.33	Consulting Agreement, dated as of April 15, 2014, by and between Energy XXI (Bermuda) Limited and T.J. Thom	10.29 to Amendment No. 1 to the Company’s Registration Statement on Form S-4 filed on April 15, 2014	333-194942

70

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10.34	Purchase Agreement, dated May 12, 2014, by and between Energy XXI Gulf Coast, Inc., Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as representatives of the Initial Purchasers and the Guarantors named therein.	10.1 to the Company’s Form 8-K filed on May 15, 2014	001-33628
12.1**	Ratio of Earnings to Fixed Charges – Energy XXI Gulf Coast, Inc.	12.1 to the Company’s Form 10-K filed on August 25, 2014	001-33628
21.1**	Subsidiary List	21.1 to the Company’s Form 10-K filed on August 25, 2014	001-33628
23.1*	Consent of UHY LLP
23.2*	Consent of Netherland, Sewell & Associates, Inc.
31.1*	Rule 13a-14(a)/15d-14(a) Certification of the Chairman and Chief Executive Officer of Energy XXI Limited
31.2*	Rule 13a-14(a)/15d-14(a) Certification of the Chief Financial Officer of Energy XXI Limited
32.1#	Certification of the Chief Executive Officer and the Chief Financial Officer under 18 U.S.C. §1350
99.1	Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists	99.1 to the Company’s Form 10-K filed on August 25, 2014	001-33628
101.INS#	XBRL Instance Document
101.SCH#	XBRL Schema Document
101.CAL#	XBRL Calculation Linkbase Document
101.DEF#	XBRL Definition Linkbase Document
101.LAB#	XBRL Label Linkbase Document
101.PRE#	XBRL Presentation Linkbase Document

(*) Filed herewith.

(**) Previously filed on August 25, 2014 as an exhibit to the original Annual Report.

(#) Furnished herewith.

(†) Executive Compensation Plan or Arrangement.

71

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-155065, 333-163736, 333-173865 and 333-177095) and on Form S-3 (No. 333-186488) of Energy XXI Ltd. (formerly Energy XXI (Bermuda) Limited) of our report dated August 25, 2014, except for Note 23, as to which the date is December 23, 2014, with respect to the consolidated financial statements of Energy XXI (Bermuda) Limited and subsidiaries as of June 30, 2014 and 2013, and for each of the three fiscal years in the period ended June 30, 2014, and our report dated August 25, 2014 with respect to the effectiveness of Energy XXI (Bermuda) Limited and subsidiaries’ internal control over financial reporting as of June 30, 2014, which appear in this Amendment to Form 10-K/A for the year ended June 30, 2014.

/s/ UHY LLP

Farmington Hills, Michigan
December 23, 2014

EX-23.2

 

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-143886, 333-147731, 333-152740, 333-155065, 333-159868, 333-163736, 333-166723, 333-173865 and 333-177095) on Form S-3 (File Nos. 333-148411, 333-148713, 333-152449, 333-158304, 333-159894, 333-165739 and 333-186488) and on Form S-4 (File Nos. 333-145639-01, 333-150823, 333-163968-05, 333-172765-05, 333-172963-05, 333-194942 and 333-191806) of Energy XXI (Bermuda) Limited (the “Company”) of the reference to Netherland, Sewell & Associates, Inc., and the inclusion of our audit letter dated August 7, 2014 (except for Note 23, as to which the date is December 23, 2014) in this Amendment to Form 10-K/A for the year ended June 30, 2014, of the Company and its subsidiaries, filed with the Securities and Exchange Commission.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:
/s/ Danny D. Simmons.

Danny D. Simmons, P.E.
President and Chief Operating Officer

Houston, Texas
December 23, 2014

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-31.1

Exhibit 31.1

CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13A – 14(A) AND RULE 15D – 14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, John D. Schiller, Jr., certify that:

1. I have reviewed this annual report on Form 10-K/A for the fiscal year ended June 30, 2014 of Energy XXI Ltd;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Date: December 23, 2014

/s/ JOHN D. SCHILLER, JR.

John D. Schiller, Jr.
Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF THE CHIEF FINANCIAL OFFICER
PURSUANT TO RULE 13A – 14(A) AND RULE 15D – 14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, David Bruce W. Busmire, certify that:

1. I have reviewed this annual report on Form 10-K/A for the fiscal year ended June 30, 2014 of Energy XXI Ltd;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Date: December 23, 2014

/s/ BRUCE W. BUSMIRE

Bruce W. Busmire
Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF
CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER
UNDER SECTION 906 OF THE
SARBANES OXLEY ACT OF 2002, 18 U.S.C. §1350

In connection with this annual report on Form 10-K/A of Energy XXI Ltd (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), John D. Schiller, Jr., Chief Executive Officer of the Company, and Bruce W. Busmire, Chief Financial Officer of the Company, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: December 23, 2014

/s/ JOHN D. SCHILLER, JR.

John D. Schiller, Jr.
Chief Executive Officer

Date: December 23, 2014

/s/ BRUCE W. BUSMIRE

Bruce W. Busmire
Chief Financial Officer

XML

Supplemental Cash Flow Information (Tables)

12 Months Ended

Jun. 30, 2014

Supplemental Cash Flow Information

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

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

Non-Cash Investing and Financing Activities

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

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

Parent Company [Member]

Supplemental Cash Flow Information

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

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

Non-Cash Investing and Financing Activities

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

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

XML

Acquisitions and Dispositions (Summary of Pro Forma Financial Information) (Details) (USD $)	3 Months Ended								12 Months Ended			1 Months Ended
	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2014
Business Acquisition [Line Items]
Exploration costs									$ 153,136,000	$ 168,512,000	$ 183,397,000
Increase in interest expense, adjustment									47,800,000	51,900,000
Decrease in interest expense, adjustment									13,700,000	7,000,000
Face value of notes	650,000,000				650,000,000				650,000,000	650,000,000		650,000,000
Debt instrument, stated interest rate	6.875%				6.875%				6.875%	6.875%		6.875%
Net earnings	(1,815,000)	7,292,000	10,495,000	43,139,000	62,053,000	40,436,000	41,332,000	18,260,000	59,111,000	162,081,000	335,827,000
EPL Oil & Gas, Inc. [Member]
Business Acquisition [Line Items]
Revenues									1,860,200,000	1,927,235,000
Operating income									277,904,000	512,869,000
Net income (loss) from continuing operations									(7,017,000)	202,904,000
Net income (loss) available to Energy XXI common stockholders									(18,506,000)	191,408,000
Net income (loss) per share available to Energy XXI common stockholders: Basic									$ (0.16)	$ 1.87
Net income (loss) per share available to Energy XXI common stockholders: Diluted									$ (0.16)	$ 1.83
Exploration costs									43,300,000
Increase to depletion, depreciation and amortization expense, adjustment									64,200,000	116,000,000
Increase in interest expense, adjustment										5,400,000
Face value of notes	510,000,000				510,000,000				510,000,000	510,000,000		510,000,000
Debt instrument, stated interest rate	8.25%				8.25%				8.25%	8.25%		8.25%
Net earnings										$ 57,600,000		$ 4,200,000

XML

Supplemental Guarantor Information (Tables)

12 Months Ended

Jun. 30, 2014

Supplemental Guarantor Information [Abstract]

Condensed Consolidating Balance Sheet

	June 30, 2014
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$                135,703	$                3,723	$                    -	$                 6,380	$                        -	$         145,806
Accounts receivable
Oil and natural gas sales			127,773	50,990	(11,688)	167,075
Joint interest billings		1,833		11,065		12,898
Insurance and other	10	3,452	517	1,460	(1)	5,438
Prepaid expenses and other current assets	230	27,705	350	44,245		72,530
Deferred income taxes		27,424		25,163		52,587
Derivative financial instruments		1,425				1,425
Total Current Assets	135,943	65,562	128,640	139,303	(11,689)	457,759
Property and Equipment
Oil and natural gas properties			3,324,923	3,197,765	1,914	6,524,602
Other property and equipment				19,760		19,760
Total Property and Equipment, net	-	-	3,324,923	3,217,525	1,914	6,544,362
Other Assets
Goodwill				327,235		327,235
Derivative financial instruments		3,035				3,035
Equity investments	1,744,908	2,969,070		2,110,608	(6,783,943)	40,643
Intercompany receivables	102,489	1,627,931	-	60,562	(1,790,982)	-
Restricted cash			325	6,025		6,350
Other assets and debt issuance costs, net	178,299	42,155		7,940	(171,000)	57,394
Total Other Assets	2,025,696	4,642,191	325	2,512,370	(8,745,925)	434,657
Total Assets	$             2,161,639	$         4,707,753	$     3,453,888	$          5,869,198	$        (8,755,700)	$      7,436,778
LIABILITIES
Current Liabilities
Accounts payable	$                           -	$              64,533	$        150,909	$             212,157	$             (11,881)	$         415,718
Accrued liabilities	1,640	12,501	28,750	154,587	(63,952)	133,526
Notes payable		21,967				21,967
Deferred income taxes	19,185				(19,185)	-
Asset retirement obligations			39,819	39,830		79,649
Derivative financial instruments		5,517		26,440		31,957
Current maturities of long-term debt		14,093		927		15,020
Total Current Liabilities	20,825	118,611	219,478	433,941	(95,018)	697,837
Long-term debt, less current maturities	342,986	2,305,906		1,266,732	(171,000)	3,744,624
Deferred income taxes		211,055		470,798	19,185	701,038
Asset retirement obligations		49	247,272	232,864		480,185
Derivative financial instruments		2,166		2,140		4,306
Intercompany payables			1,736,240		(1,736,240)	-
Other liabilities				10,958		10,958
Total Liabilities	363,811	2,637,787	2,202,990	2,417,433	(1,983,073)	5,638,948
Stockholders’ Equity
Preferred stock
7.25% Convertible perpetual preferred stock						-
5.625% Convertible perpetual preferred stock	1					1
Common stock	468	1		10	(11)	468
Additional paid-in capital	1,837,462	2,092,439	273,129	3,580,004	(5,945,572)	1,837,462
Retained earnings (accumulated deficit)	(19,628)	(2,040)	977,769	(101,521)	(874,206)	(19,626)
Accumulated other comprehensive (loss) income	(20,475)	(20,434)		(26,728)	47,162	(20,475)
Total Stockholders’ Equity	1,797,828	2,069,966	1,250,898	3,451,765	(6,772,627)	1,797,830
Total Liabilities and Stockholders’ Equity	$             2,161,639	$         4,707,753	$     3,453,888	$          5,869,198	$        (8,755,700)	$      7,436,778

ENERGY XXI (BERMUDA) LIMITED

CONDENSED CONSOLIDATING BALANCE SHEET

(In Thousands)

	June 30, 2013
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$                   1,334	$                       -	$                    -	$                    137	$               (1,471)	$                   -
Accounts receivable
Oil and natural gas sales			150,007		(17,486)	132,521
Joint interest billings		9,505				9,505
Insurance and other		6,031	495	219		6,745
Prepaid expenses and other current assets	235	47,492	372	2,638	1	50,738
Derivative financial instruments		38,389				38,389
Total Current Assets	1,569	101,417	150,874	2,994	(18,956)	237,898
Property and Equipment
Oil and natural gas properties		16,553	3,272,952			3,289,505
Other property and equipment				17,003		17,003
Total Property and Equipment, net	-	16,553	3,272,952	17,003	-	3,306,508
Other Assets
Derivative financial instruments		21,926				21,926
Equity investments	1,259,247	1,066,803		1,544,751	(3,858,002)	12,799
Intercompany receivables	95,627	1,904,655		56,715	(2,056,997)	-
Deferred income taxes				29,884	(29,884)	-
Other assets and debt issuance costs, net	171,000	24,791		7,789	(171,000)	32,580
Total Other Assets	1,525,874	3,018,175	-	1,639,139	(6,115,883)	67,305
Total Assets	$            1,527,443	$        3,136,145	$     3,423,826	$          1,659,136	$        (6,134,839)	$    3,611,711
LIABILITIES
Current Liabilities
Accounts payable	$                          -	$           104,263	$        133,045	$                 1,258	$             (18,956)	$       219,610
Accrued liabilities	479	25,001	30,393	105,598	(56,279)	105,192
Notes payable	175	22,349				22,524
Deferred income taxes				20,517		20,517
Asset retirement obligations			29,500			29,500
Derivative financial instruments		40				40
Current maturities of long-term debt		18,838		716		19,554
Total Current Liabilities	654	170,491	192,938	128,089	(75,235)	416,937
Long-term debt, less current maturities	—	1,279,843		241,648	(171,000)	1,350,491
Deferred income taxes	16,883	153,805			(29,884)	140,804
Asset retirement obligations		50	258,268			258,318
Intercompany payables			1,913,195		(1,913,195)	-
Other liabilities				7,915		7,915
Total Liabilities	17,537	1,604,189	2,364,401	377,652	(2,189,314)	2,174,465
Stockholders’ Equity
Preferred stock
7.25% Convertible perpetual preferred stock						-
5.625% Convertible perpetual preferred stock	1					1
Common stock	396	1				397
Additional paid-in capital	1,512,310	1,426,351	369,195	1,370,648	(3,166,193)	1,512,311
Retained earnings (accumulated deficit)	(29,352)	79,304	690,231	(43,052)	(726,483)	(29,352)
Accumulated other comprehensive (loss) income	26,551	26,300	(1)	26,551	(52,849)	26,552
Treasury stock				(72,663)		(72,663)
Total Stockholders’ Equity	1,509,906	1,531,956	1,059,425	1,281,484	(3,945,525)	1,437,246
Total Liabilities and Stockholders’ Equity	$            1,527,443	$        3,136,145	$     3,423,826	$          1,659,136	$        (6,134,839)	$    3,611,711

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	For the Year Ended June 30, 2014
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Revenues
Crude oil sales	$                       -	$      (11,525)	$    1,046,263	$           56,485	$                        -	$     1,091,223
Natural gas sales		3,710	132,134	3,658		139,502
Total Revenues	-	(7,815)	1,178,397	60,143	-	1,230,725
Costs and Expenses
Lease operating		(325)	348,027	18,045		365,747
Production taxes		51	4,716	660		5,427
Gathering and transportation			23,532			23,532
Depreciation, depletion and amortization			399,086	26,340	(2,107)	423,319
Accretion of asset retirement obligations			28,161	2,022		30,183
General and administrative expense	7,380	1,134	81,380	6,508		96,402
Loss (gain) on derivative financial instruments		5,704				5,704
Total Costs and Expenses	7,380	6,564	884,902	53,575	(2,107)	950,314
Operating Income (Loss )	(7,380)	(14,379)	293,495	6,568	2,107	280,411
Other Income (Expense)
Income (loss) from equity method investees	66,995	296,279		92,191	(460,246)	(4,781)
Other income - net	19,923	1,954		17,808	(36,387)	3,298
Interest expense	(14,485)	(138,336)	(5,957)	(40,337)	36,387	(162,728)
Total Other Income (Expense)	72,433	159,897	(5,957)	69,662	(460,246)	(164,211)
Income (Loss) Before Income Taxes	65,053	145,518	287,538	76,230	(458,139)	116,200
Income Tax Expense	5,942	48,546		2,601		57,089
Net Income (Loss)	59,111	96,972	287,538	73,629	(458,139)	59,111
Preferred Stock Dividends	11,489				-	11,489
Net Income (Loss) Available for Common Stockholders	$          47,622	$      96,972	$       287,538	$           73,629	$         (458,139)	$          47,622
Comprehensive Income (Loss)
Net Income (Loss)	$          59,111	$      96,972	$       287,538	$           73,629	$         (458,139)	$          59,111
Other Comprehensive Income (Loss)	(47,027)	(38,523)		(8,504)	47,027	(47,027)
Comprehensive Income (Loss)	$          12,084	$      58,449	$       287,538	$           65,125	$         (411,112)	$          12,084

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	For the Year Ended June 30, 2013
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Revenues
Crude oil sales	$                       -	$       13,295	$    1,067,687	$                     -	$                        -	$     1,080,982
Natural gas sales		15,110	112,753			127,863
Total Revenues	-	28,405	1,180,440	-	-	1,208,845
Costs and Expenses
Lease operating		(3,249)	340,412			337,163
Production taxes		(658)	5,904			5,246
Gathering and transportation			24,168			24,168
Depreciation, depletion and amortization			372,252	3,972		376,224
Accretion of asset retirement obligations			30,885			30,885
General and administrative expense	7,439	2,820	61,089	250		71,598
Loss (gain) on derivative financial instruments		1,915		(159)		1,756
Total Costs and Expenses	7,439	828	834,710	4,063	-	847,040
Operating Income (Loss)	(7,439)	27,577	345,730	(4,063)	-	361,805
Other Income (Expense)
Income (loss) from equity method investees	156,516	333,039		176,979	(672,931)	(6,397)
Other income - net	18,584	1,849	12	17,833	(36,313)	1,965
Interest expense	(5)	(93,200)	(15,160)	(36,607)	36,313	(108,659)
Total Other Income (Expense)	175,095	241,688	(15,148)	158,205	(672,931)	(113,091)
Income (Loss) Before Income Taxes	167,656	269,265	330,582	154,142	(672,931)	248,714
Income Tax Expense (Benefit)	5,575	85,889		(4,831)		86,633
Net Income (Loss)	162,081	183,376	330,582	158,973	(672,931)	162,081
Preferred Stock Dividends	11,496					11,496
Net Income (Loss) Available for Common Stockholders	$        150,585	$     183,376	$       330,582	$      158,973	$         (672,931)	$        150,585
Comprehensive Income (Loss)
Net Income (Loss)	$        162,081	$     183,376	$       330,582	$      158,973	$         (672,931)	$        162,081
Other Comprehensive Income (Loss)	(31,051)	(32,985)		1,934	31,051	(31,051)
Comprehensive Income (Loss)	$        131,030	$     150,391	$       330,582	$      160,907	$         (641,880)	$        131,030

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	For the Year Ended June 30, 2012
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Revenues
Crude oil sales	$                       -	$           645	$    1,185,986	$                     -	$                        -	$     1,186,631
Natural gas sales		29,871	86,901			116,772
Total Revenues	-	30,516	1,272,887	-	-	1,303,403
Costs and Expenses
Lease operating		(343)	311,158			310,815
Production taxes		4	7,257			7,261
Gathering and transportation			16,371			16,371
Depreciation, depletion and amortization			364,281	3,182		367,463
Accretion of asset retirement obligations			39,161			39,161
General and administrative expense	6,990	3,476	75,603	207		86,276
Loss (gain) on derivative financial instruments		(7,261)		33		(7,228)
Total Costs and Expenses	6,990	(4,124)	813,831	3,422	-	820,119
Operating Income (Loss)	(6,990)	34,640	459,056	(3,422)	-	483,284
Other Income (Expense)
Income (loss) from equity method investees	331,110	459,057		315,146	(1,105,313)	-
Other income - net	16,722	1,191	1	17,828	(35,671)	71
Interest expense		(108,731)		(35,822)	35,671	(108,882)
Total Other Income (Expense)	347,832	351,517	1	297,152	(1,105,313)	(108,811)
Income (Loss) Before Income Taxes	340,842	386,157	459,057	293,730	(1,105,313)	374,473
Income Tax Expense (Benefit)	5,015	71,010		(37,379)		38,646
Net Income (Loss)	335,827	315,147	459,057	331,109	(1,105,313)	335,827
Induced Conversion of Preferred Stock	6,068					6,068
Preferred Stock Dividends	13,028					13,028
Net Income (Loss) Available for Common Stockholders	316,731	315,147	459,057	331,109	(1,105,313)	316,731
Comprehensive Income (Loss)
Net Income ( Loss)	$        335,827	$    315,147	$       459,057	$      331,109	$      (1,105,313)	$        335,827
Other Comprehensive Income (Loss), net	126,087	126,087			(126,087)	126,087
Comprehensive Income (Loss)	$        461,914	$    441,234	$       459,057	$      331,109	$      (1,231,400)	$        461,914

Condensed Consolidating Statement of Cash Flows

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

	For the Year Ended June 30, 2014
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Cash Flows From Operating Activities
Net income (Loss)	$               59,111	$        96,972	$        287,538	$             73,629	$            (458,139)	$           59,111
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization			399,086	26,340	(2,107)	423,319
Deferred income tax expense (benefit)	2,301	48,546		2,601		53,448
Change in derivative financial instruments
Other – net		(1,793)				(1,793)
Accretion of asset retirement obligations			28,161	2,022		30,183
Loss (income) from equity method investees	(66,995)	(296,279)		(92,191)	460,246	4,781
Amortization and write-off of debt issuance costs and other	7,219	6,555				13,774
Stock-based compensation	6,712				(1)	6,711
Changes in operating assets and liabilities
Accounts receivable	(10)	22,708	22,212	18,372	1	63,283
Prepaid expenses and other current assets	(18)	19,746	23	(13,733)	1	6,019
Settlement of asset retirement obligations			(57,391)			(57,391)
Accounts payable and accrued liabilities	(5,852)	87,745	(256,799)	1,284,956	(1,166,035)	(55,985)
Net Cash Provided by (Used in) Operating Activities	2,468	(15,800)	422,830	1,301,996	(1,166,034)	545,460
Cash Flows from Investing Activities
Acquisitions, net of cash acquired			(37,657)	(811,984)		(849,641)
Capital expenditures		16,746	(513,096)	(292,326)		(788,676)
Insurance payments received			1,983			1,983
Change in equity method investments				(34,294)		(34,294)
Proceeds from the sale of properties			126,265			126,265
Intercompany investment	(185,568)	(979,420)		(2,570)	1,167,558	-
Transfer to restricted cash			(325)			(325)
Other				113		113
Net Cash Provided by (Used in) Investing Activities	(185,568)	(962,674)	(422,830)	(1,141,061)	1,167,558	(1,544,575)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	3,994					3,994
Discount on convertible debt allocated to additional paid-in capital	63,432					63,432
Repurchase of company common stock	(30,824)			(153,439)		(184,263)
Dividends to shareholders - common	(34,680)					(34,680)
Dividends to shareholders - preferred	(11,489)					(11,489)
Proceeds from long-term debt	336,568	3,085,145		(840)		3,420,873
Payments on long-term debt	-	(2,079,072)		(413)		(2,079,485)
Debt issuance costs	(9,585)	(23,876)				(33,461)
Other	53				(53)	-
Net Cash Provided by (Used in) Financing Activities	317,469	982,197	-	(154,692)	(53)	1,144,921
Net Increase in Cash and Cash Equivalents	134,369	3,723	-	6,243	1,471	145,806
Cash and Cash Equivalents, beginning of year	1,334	-	-	137	(1,471)	-
Cash and Cash Equivalents, end of year	$             135,703	$          3,723	$                   -	$               6,380	$                         -	$         145,806

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

	For the Year Ended June 30, 2013
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Cash Flows From Operating Activities
Net income (Loss)	$             162,081	$      183,376	$        330,582	$            158,973	$            (672,931)	$          162,081
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization			372,252	3,972		376,224
Deferred income tax expense	(7,297)	85,889		(4,831)		73,761
Change in derivative financial instruments
Proceeds from sale of derivative instruments		635		125		760
Other – net		(27,357)		(159)		(27,516)
Accretion of asset retirement obligations			30,885			30,885
Loss (income) from equity method investees	(156,516)	(333,039)		(176,979)	672,931	6,397
Amortization and write-off of debt issuance costs and other		6,857		41		6,898
Stock-based compensation	3,504				1	3,505
Changes in operating assets and liabilities
Accounts receivable		14,422	(13,156)	424		1,690
Prepaid expenses and other current assets	8,772	2,865	760	103	(1)	12,499
Settlement of asset retirement obligations			(41,939)			(41,939)
Accounts payable and accrued liabilities	15,437	(284,637)	269,560	79,024	(46,481)	32,903
Net Cash Provided by (Used in) Operating Activities	25,981	(350,989)	948,944	60,693	(46,481)	638,148
Cash Flows from Investing Activities
Acquisitions, net of cash acquired			(161,164)			(161,164)
Capital expenditures		(17,144)	(787,774)	(11,187)		(816,105)
Change in equity method investments				(16,693)		(16,693)
Intercompany investment	(4,010)			(41,000)	45,010	-
Other			(6)	(35)		(41)
Net Cash Provided by (Used in) Investing Activities	(4,010)	(17,144)	(948,944)	(68,915)	45,010	(994,003)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	7,021			-		7,021
Repurchase of company common stock				(58,666)		(58,666)
Dividends to shareholders - common	(25,992)			-		(25,992)
Dividends to shareholders - preferred	(11,496)			-		(11,496)
Proceeds from long-term debt		1,571,061		5,490		1,576,551
Payments on long-term debt		(1,243,545)		(303)		(1,243,848)
Debt issuance costs		(4,777)		(28)		(4,805)
Other				3		3
Net Cash Provided by (Used in) Financing Activities	(30,467)	322,739	-	(53,504)	-	238,768
Net Decrease in Cash and Cash Equivalents	(8,496)	(45,394)	-	(61,726)	(1,471)	(117,087)
Cash and Cash Equivalents, beginning of year	9,830	45,394	-	61,863	-	117,087
Cash and Cash Equivalents, end of year	$                 1,334	$                  -	$                   -	$                   137	$                (1,471)	$                     -

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

	For the Year Ended June 30, 2012
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Cash Flows From Operating Activities
Net income (Loss)	$             335,827	$      315,147	$        459,057	$            331,109	$         (1,105,313)	$          335,827
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization			364,281	3,182		367,463
Deferred income tax expense	5,015	71,011		(37,230)		38,796
Change in derivative financial instruments
Proceeds from sale of derivative instruments		66,522				66,522
Other – net		(52,155)				(52,155)
Accretion of asset retirement obligations		-	39,161			39,161
Loss (income) from equity method investees	(331,110)	(459,057)		(315,146)	1,105,313	-
Amortization and write-off of debt issuance costs and other		7,468		91		7,559
Stock-based compensation	11,702			58		11,760
Changes in operating assets and liabilities
Accounts receivable		(17,406)	12,984	(573)		(4,995)
Prepaid expenses and other current assets	(8,703)	(5,565)	892	(2,514)		(15,890)
Settlement of asset retirement obligations			(14,990)			(14,990)
Accounts payable and accrued liabilities	(15,919)	232,527	(298,228)	93,157	(5,081)	6,456
Net Cash Provided by (Used in) Operating Activities	(3,188)	158,492	563,157	72,134	(5,081)	785,514
Cash Flows from Investing Activities
Acquisitions, net of cash acquired			(6,401)			(6,401)
Capital expenditures			(565,978)	(4,692)		(570,670)
Insurance payments received			6,472			6,472
Change in equity method investments				(2,201)		(2,201)
Proceeds from the sale of properties			2,750			2,750
Intercompany investment and other	(1,000)			(3,624)	5,081	457
Net Cash Provided by (Used in) Investing Activities	(1,000)	-	(563,157)	(10,517)	5,081	(569,593)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	9,839					9,839
Discount on convertible debt allocated to additional paid-in capital						-
Conversion of preferred stock to common stock	(6,040)					(6,040)
Dividends to shareholders – preferred	(18,682)					(18,682)
Proceeds from long-term debt		896,717				896,717
Payments on long-term debt		(1,008,300)				(1,008,300)
Other	212	(859)		(128)		(775)
Net Cash Provided by (Used in) Financing Activities	(14,671)	(112,442)	-	(128)	-	(127,241)
Net Increase (Decrease) in Cash and Cash Equivalents	(18,859)	46,050	-	61,489	-	88,680
Cash and Cash Equivalents, beginning of year	28,689	(656)	-	374	-	28,407
Cash and Cash Equivalents, end of year	$                 9,830	$        45,394	$                   -	$              61,863	$                         -	$          117,087

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Derivative Financial Instruments (Schedule of Derivative Instruments Gain (Loss) in Statement of Financial Performance) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Total cash settlements	$ 9,366	$ (28,406)	$ (28,602)
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments	6,339	881	(3,479)
(Gain) loss on derivative financial instruments Realized mark to market (gain) loss		(760)	(66,522)
Total (gain) loss on derivative financial instruments	1,793	27,516	52,155
Total (gain) loss	15,070	(26,650)	(35,830)
Crude Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total cash settlements	12,985	(13,296)	(438)
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total cash settlements	(3,619)	(15,110)	(28,164)
Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments	6,339	881	(3,479)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative financial instruments Realized mark to market (gain) loss	(1,065)	1,686	(4,542)
Unrealized mark to market (gain) loss	430	(811)	793
Total (gain) loss on derivative financial instruments	$ 5,704	$ 1,756	$ (7,228)

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Property and Equipment (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014
Property and Equipment [Abstract]
Costs incurred	$ 185.3

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Employee Benefit Plans (Compensation Expense Recognized and Shares Issued Under Employee Stock Purchase Plan) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Employee Benefit Plans [Abstract]
Compensation expense	$ 866	$ 813	$ 729
Shares issued	92,297	74,806	46,985

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Supplemental Guarantor Information (Condensed Consolidating Statement of Cash Flows) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Cash Flows From Operating Activities
Net income	$ 59,111	$ 162,081	$ 335,827
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	423,319	376,224	367,463
Deferred income tax expense (benefit)	53,448	73,761	38,796
Change in derivative financial instruments
Proceeds from derivative instruments		760	66,522
Other - net	(1,793)	(27,516)	(52,155)
Accretion of asset retirement obligations	30,183	30,885	39,161
Income (loss) from equity method investees	4,781	6,397
Amortization and write-off of debt issuance costs and other	13,774	6,898	7,559
Stock-based compensation	6,711	3,505	11,760
Changes in operating assets and liabilities
Accounts receivable	63,283	1,690	(4,995)
Prepaid expenses and other current assets	6,019	12,499	(15,890)
Settlement of asset retirement obligations	(57,391)	(41,939)	(14,990)
Accounts payable and accrued liabilities	(55,985)	32,903	6,456
Net Cash Provided by Operating Activities	545,460	638,148	785,514
Cash Flows from Investing Activities
Acquisitions, net of cash acquired	(849,641)	(161,164)	(6,401)
Capital expenditures	(788,676)	(816,105)	(570,670)
Insurance payments received	1,983		6,472
Change in equity method investments	(34,294)	(16,693)	(2,201)
Proceeds from the sale of properties	126,265		2,750
Transfer to restricted cash	(325)
Other	113	(41)	457
Net Cash Used in Investing Activities	(1,544,575)	(994,003)	(569,593)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	3,994	7,021	9,839
Discount on convertible debt allocated to additional paid-in capital	63,432
Conversion of preferred stock to common stock			(6,040)
Repurchase of company common stock	(184,263)	(58,666)
Dividends to shareholders - common	(34,680)	(25,992)
Dividends to shareholders - preferred	(11,489)	(11,496)	(18,682)
Proceeds from long-term debt	3,420,873	1,576,551	896,717
Payments on long-term debt	(2,079,485)	(1,243,848)	(1,008,300)
Debt issuance costs	(33,461)	(4,805)
Other		3	(775)
Net Cash Provided by (Used in) Financing Activities	1,144,921	238,768	(127,241)
Net Increase (Decrease) in Cash and Cash Equivalents	145,806	(117,087)	88,680
Cash and Cash Equivalents, beginning of year		117,087	28,407
Cash and Cash Equivalents, end of year	145,806		117,087
Parent Company [Member]
Cash Flows From Operating Activities
Net income	59,111	162,081	335,827
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Deferred income tax expense (benefit)	2,301	(7,297)	5,015
Change in derivative financial instruments
Income (loss) from equity method investees	(66,995)	(156,516)	(331,110)
Amortization and write-off of debt issuance costs and other	7,219
Stock-based compensation	6,712	3,504	11,702
Changes in operating assets and liabilities
Accounts receivable	(10)
Prepaid expenses and other current assets	(18)	8,772	(8,703)
Accounts payable and accrued liabilities	(5,852)	15,437	(15,919)
Net Cash Provided by Operating Activities	2,468	25,981	(3,188)
Cash Flows from Investing Activities
Change in equity method investments	(185,568)	(4,010)	(1,000)
Intercompany investment and other	(185,568)	(4,010)
Other			(1,000)
Net Cash Used in Investing Activities	(185,568)	(4,010)	(1,000)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	3,994	7,021	9,839
Discount on convertible debt allocated to additional paid-in capital	63,432
Conversion of preferred stock to common stock			(6,040)
Repurchase of company common stock	(30,824)
Dividends to shareholders - common	(34,680)	(25,992)
Dividends to shareholders - preferred	(11,489)	(11,496)	(18,682)
Proceeds from long-term debt	336,568
Debt issuance costs	(9,585)
Other	53		212
Net Cash Provided by (Used in) Financing Activities	317,469	(30,467)	(14,671)
Net Increase (Decrease) in Cash and Cash Equivalents	134,369	(8,496)	(18,859)
Cash and Cash Equivalents, beginning of year	1,334	9,830	28,689
Cash and Cash Equivalents, end of year	135,703	1,334	9,830
Energy XXI Gulf Coast Inc [Member]
Cash Flows From Operating Activities
Net income	96,972	183,376	315,147
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Deferred income tax expense (benefit)	48,546	85,889	71,011
Change in derivative financial instruments
Proceeds from derivative instruments		635	66,522
Other - net	(1,793)	(27,357)	(52,155)
Income (loss) from equity method investees	(296,279)	(333,039)	(459,057)
Amortization and write-off of debt issuance costs and other	6,555	6,857	7,468
Changes in operating assets and liabilities
Accounts receivable	22,708	14,422	(17,406)
Prepaid expenses and other current assets	19,746	2,865	(5,565)
Accounts payable and accrued liabilities	87,745	(284,637)	232,527
Net Cash Provided by Operating Activities	(15,800)	(350,989)	158,492
Cash Flows from Investing Activities
Capital expenditures	16,746	(17,144)
Intercompany investment and other	(979,420)
Net Cash Used in Investing Activities	(962,674)	(17,144)
Cash Flows from Financing Activities
Discount on convertible debt allocated to additional paid-in capital
Proceeds from long-term debt	3,085,145	1,571,061	896,717
Payments on long-term debt	(2,079,072)	(1,243,545)	(1,008,300)
Debt issuance costs	(23,876)	(4,777)
Other			(859)
Net Cash Provided by (Used in) Financing Activities	982,197	322,739	(112,442)
Net Increase (Decrease) in Cash and Cash Equivalents	3,723	(45,394)	46,050
Cash and Cash Equivalents, beginning of year		45,394	(656)
Cash and Cash Equivalents, end of year	3,723		45,394
Guarantor Subsidiaries [Member]
Cash Flows From Operating Activities
Net income	287,538	330,582	459,057
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	399,086	372,252	364,281
Change in derivative financial instruments
Accretion of asset retirement obligations	28,161	30,885	39,161
Changes in operating assets and liabilities
Accounts receivable	22,212	(13,156)	12,984
Prepaid expenses and other current assets	23	760	892
Settlement of asset retirement obligations	(57,391)	(41,939)	(14,990)
Accounts payable and accrued liabilities	(256,799)	269,560	(298,228)
Net Cash Provided by Operating Activities	422,830	948,944	563,157
Cash Flows from Investing Activities
Acquisitions, net of cash acquired	(37,657)	(161,164)	(6,401)
Capital expenditures	(513,096)	(787,774)	(565,978)
Insurance payments received	1,983		6,472
Proceeds from the sale of properties	126,265		2,750
Transfer to restricted cash	(325)
Other		(6)
Net Cash Used in Investing Activities	(422,830)	(948,944)	(563,157)
Cash Flows from Financing Activities
Discount on convertible debt allocated to additional paid-in capital
Non-Guarantor Subsidiaries [Member]
Cash Flows From Operating Activities
Net income	73,629	158,973	331,109
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	26,340	3,972	3,182
Deferred income tax expense (benefit)	2,601	(4,831)	(37,230)
Change in derivative financial instruments
Proceeds from derivative instruments		125
Other - net		(159)
Accretion of asset retirement obligations	2,022
Income (loss) from equity method investees	(92,191)	(176,979)	(315,146)
Amortization and write-off of debt issuance costs and other		41	91
Stock-based compensation			58
Changes in operating assets and liabilities
Accounts receivable	18,372	424	(573)
Prepaid expenses and other current assets	(13,733)	103	(2,514)
Accounts payable and accrued liabilities	1,284,956	79,024	93,157
Net Cash Provided by Operating Activities	1,301,996	60,693	72,134
Cash Flows from Investing Activities
Acquisitions, net of cash acquired	(811,984)
Capital expenditures	(292,326)	(11,187)	(4,692)
Change in equity method investments	(34,294)	(16,693)	(2,201)
Intercompany investment and other	(2,570)	(41,000)
Other	113	(35)	(3,624)
Net Cash Used in Investing Activities	(1,141,061)	(68,915)	(10,517)
Cash Flows from Financing Activities
Discount on convertible debt allocated to additional paid-in capital
Repurchase of company common stock	(153,439)	(58,666)
Proceeds from long-term debt	(840)	5,490
Payments on long-term debt	(413)	(303)
Debt issuance costs		(28)
Other		3	(128)
Net Cash Provided by (Used in) Financing Activities	(154,692)	(53,504)	(128)
Net Increase (Decrease) in Cash and Cash Equivalents	6,243	(61,726)	61,489
Cash and Cash Equivalents, beginning of year	137	61,863	374
Cash and Cash Equivalents, end of year	6,380	137	61,863
Reclassifications & Eliminations [Member]
Cash Flows From Operating Activities
Net income	(458,139)	(672,931)	(1,105,313)
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	(2,107)
Change in derivative financial instruments
Income (loss) from equity method investees	460,246	672,931	1,105,313
Stock-based compensation	(1)	1
Changes in operating assets and liabilities
Accounts receivable	1
Prepaid expenses and other current assets	1	(1)
Accounts payable and accrued liabilities	(1,166,035)	(46,481)	(5,081)
Net Cash Provided by Operating Activities	(1,166,034)	(46,481)	(5,081)
Cash Flows from Investing Activities
Intercompany investment and other	1,167,558	45,010
Other			5,081
Net Cash Used in Investing Activities	1,167,558	45,010	5,081
Cash Flows from Financing Activities
Discount on convertible debt allocated to additional paid-in capital
Other	(53)
Net Cash Provided by (Used in) Financing Activities	(53)
Net Increase (Decrease) in Cash and Cash Equivalents	1,471	(1,471)
Cash and Cash Equivalents, beginning of year	(1,471)
Cash and Cash Equivalents, end of year		$ (1,471)

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Selected Quarterly Financial Data (Tables)

12 Months Ended

Jun. 30, 2014

Selected Quarterly Financial Data [Abstract]

Unaudited Quarterly Financial Data

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

		Year Ended June 30, 2014
		Fourth		Third		Second		First
		Quarter		Quarter		Quarter		Quarter
Revenues	$	324,134	$	285,183	$	296,816	$	324,592
Operating income		54,677		64,801		61,502		99,431
Net income (loss)	$	(1,815)	$	7,292	$	10,495	$	43,139
Preferred stock dividends		2,872		2,872		2,872		2,873
Net income (loss) available for common stockholders	$	(4,687)	$	4,420	$	7,623	$	40,266
Net income (loss) per share attributable to common stockholders (1)
Basic	$	(0.06)	$	0.06	$	0.10	$	0.53
Diluted		(0.06)		0.06		0.10		0.51
		Year Ended June 30, 2013
		Fourth		Third		Second		First
		Quarter		Quarter		Quarter		Quarter
Revenues	$	314,325	$	303,774	$	320,519	$	270,227
Operating income		111,747		99,870		93,537		56,651
Net income	$	62,053	$	40,436	$	41,332	$	18,260
Preferred stock dividends		2,873		2,873		2,874		2,876
Net income available for common stockholders	$	59,180	$	37,563	$	38,458	$	15,384
Net income per share attributable to common stockholders (1)
Basic	$	0.75	$	0.47	$	0.48	$	0.19
Diluted		0.72		0.46		0.47		0.19

_______________________

(1)The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

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Organization and Summary of Significant Accounting Policies (Policy)

12 Months Ended

Jun. 30, 2014

Organization and Summary of Significant Accounting Policies [Abstract]

Nature of Operations

Nature of Operations.   Energy XXI (Bermuda) Limited was incorporated in Bermuda on July 25, 2005. Headquartered in Houston, Texas, we are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico.

References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries.  We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

Principles of Consolidation and Reporting

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported consolidated net income, consolidated stockholders’ equity or consolidated cash flows.

Use of Estimates

Use of Estimates.  The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such difference may be material.

Cash and Cash Equivalents and Restricted Cash

Cash and Cash Equivalents.  We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents.

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

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts.  Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts.  We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable.  Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.  As of June 30, 2014 and 2013, no allowance for doubtful accounts was necessary.

Oil and Gas Properties

Oil and Natural Gas Properties.  We use the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. 

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated.  We also allocate a portion of our acquisition costs to unevaluated properties based on fair value.  Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict.

Depreciation, Depletion and Amortization

Depreciation, Depletion and Amortization.The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization.  The depreciable base of oil and natural gas properties is amortized using the unit-of-production method. 

Weather Based Insurance Linked Securities

Weather Based Insurance Linked Securities. We obtain Weather Based Insurance Linked Securities (“Securities”), to mitigate potential loss to our oil and natural gas properties from hurricanes in the Gulf of Mexico. These Securities provide for payments of negotiated amounts should a pre-defined category hurricane pass within specific pre-defined areas encompassing our oil and natural gas producing fields. Since these Securities were obtained to mitigate potential loss due to hurricanes in the Gulf of Mexico, the majority of the premiums associated with these Securities are charged to expense during the period associated with the hurricane season, typically June 1 to November 30. The amortization of insurance premiums for these Securities is recorded as a component of our lease operating expense. 

Other Property and Equipment

Other Property and Equipment.  Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets.  These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years.  Repairs and maintenance costs are expensed in the period incurred.

Business Combinations

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

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

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

Goodwill

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

Derivative Instruments

Derivative Instruments. We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Gains or losses resulting from transactions designated as cash flow hedges are recorded at market value and are recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of income as the physical production hedged by the contracts is delivered. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized directly in earnings.

The net cash flows related to any recognized gains or losses associated with cash flow hedges are reported as oil and natural gas revenue and presented in cash flow from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contract is delivered.

Debt Issuance Costs

Debt Issuance Costs.  Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the scheduled maturity of the debt utilizing the straight-line method, which approximates the interest method.

Asset Retirement Obligations

Asset Retirement Obligations. Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

Common Stock

Common Stock. Refers to the $0.005 par value per share capital stock as designated in the Company’s Certificate of Incorporation.  Treasury Stock is accounted for using the cost method.

Revenue Recognition

Revenue Recognition. We recognize oil and natural gas revenue under the entitlement method of accounting.  Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices.

General and Administrative Expense

General and Administrative Expense.  Under the full cost method of accounting, a portion of our general and administrative expense that is directly identified with our acquisition, exploration and development activities is capitalized as part of oil and natural gas properties.  These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to directly support those employees that are directly involved in acquisition, exploration and development activities.  The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities.  Our capitalized general and administrative expense directly related to our acquisition, exploration and development activities for the years ended June 30, 2014, 2013 and 2012 was $64.5 million, $37.6 million and $38.3 million, respectively.

Share-Based Compensation

Share-Based Compensation.Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award.  Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period.

Income Taxes

Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate.

When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate any tax operating loss and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized in our consolidated financial statements.  At June 30, 2014 we maintained a $22.5 million valuation allowance against our net deferred tax assets due to our judgment that our existing State of Louisiana net operating loss (“NOL”) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years.  We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.  In light of our capital structure, U.S. withholding taxes attributable to interest due on loans from the Bermuda parent to the U.S. operating companies is provided as the interest accrues.  This U.S. withholding tax (at 30%) is due when the interest is actually paid, and may not be offset or reduced by U.S. operating activity; although the interest expense is generally deductible in the U.S. when paid, subject to certain other limitations. 

We adopted the provisions of ASC Topic 740-10 (formally known as FIN 48, addressing “Uncertain Tax Positions”) and applied this guidance as of July 1, 2007.  As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of ASC Topic 740-10 nor have we recorded any gross unrecognized tax benefit related to Uncertain Tax Positions. 

Earnings per Share

Earnings per Share. The Earnings per Share (“EPS”) amounts have been calculated based on the weighted-average number of shares of common stock outstanding for the year.  Diluted EPS reflects the potential dilution, using the treasury stock method.  The diluted EPS calculation includes shares of common stock from the assumed conversion of the Company’s redeemable preferred stock.

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Employee Benefit Plans (Annual Employer Contribution) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Profit Sharing Plan Contribution [Line Items]
Total contributions	$ 8,228	$ 6,119	$ 6,209
Profit Sharing Plan [Member]
Profit Sharing Plan Contribution [Line Items]
Total contributions	4,833	2,738	3,014
401 (k) Plan [Member]
Profit Sharing Plan Contribution [Line Items]
Total contributions	$ 3,395	$ 3,381	$ 3,195

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Stockholders' Equity (Narrative) (Details) (USD $)	0 Months Ended	1 Months Ended		3 Months Ended								12 Months Ended		0 Months Ended	3 Months Ended	0 Months Ended
	Jun. 03, 2014	Feb. 28, 2014	May 31, 2013	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Jun. 30, 2014	Jun. 30, 2013	Jul. 16, 2014	Jun. 30, 2014	Nov. 18, 2013
Class of Stock [Line Items]
Cash dividend per share				$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.07	$ 0.07	$ 0.07
Common stock, shares authorized							200,000,000					200,000,000	200,000,000		200,000,000
Common stock, par value							$ 0.005					$ 0.005	$ 0.005		$ 0.005
Dividends payment date				Jun. 13, 2014	Mar. 14, 2014	Dec. 13, 2013	Sep. 13, 2013	Jun. 14, 2013	Mar. 15, 2013	Dec. 14, 2012	Sep. 14, 2012
Dividends payment record date				May 30, 2014	Feb. 28, 2014	Nov. 29, 2013	Aug. 30, 2013	May 31, 2013	Mar. 01, 2013	Nov. 30, 2012	Aug. 31, 2012
Stock repurchase program, authorized amount			$ 250,000,000
Stock repurchased, value												94,200,000	72,700,000
Stock repurchased, number of shares												3,700,463	2,938,900
Stock repurchased, weighted average price per share												$ 25.45	$ 24.70
Face value of notes							650,000,000					650,000,000	650,000,000		650,000,000
Debt instrument, stated interest rate							6.875%					6.875%	6.875%		6.875%
Stock repurchase program, remaining authorized amount												83,200,000
Treasury stock, shares retired		2,087,126
Treasury stock, shares		7,329,100					2,938,900						2,938,900
Treasury shares reissued	7,329,100
Preferred stock, shares authorized							7,500,000					7,500,000	7,500,000		7,500,000
Shares issued upon the closing of EPL acquisition	23,320,955
Dividend payment terms													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.
Percentage of market value of shares at which dividend paid in shares of common stock shall be valued												95.00%			95.00%
Subsidiary of Common Parent [Member]
Class of Stock [Line Items]
Stock repurchased, value												76,000,000
Stock repurchased, number of shares												2,776,200
Stock repurchased, weighted average price per share												$ 27.39
Subsequent Event [Member]
Class of Stock [Line Items]
Cash dividend per share														$ 0.12
Dividends payment date														Sep. 12, 2014	Sep. 12, 2014
Common stock, dividends, per share, declared															$ 0.12
Dividends payment record date														Aug. 29, 2014	Aug. 29, 2014
Dividends declared date														Jul. 16, 2014	Jul. 16, 2014
7.25% Convertible Perpetual Preferred Stock [Member]
Class of Stock [Line Items]
Preferred stock dividend rate												7.25%	7.25%
5.625% Convertible Perpetual Preferred Stock [Member]
Class of Stock [Line Items]
Preferred stock dividend rate												5.625%	5.625%
Conversion of preferred stock to common stock, shares												428	929
Common stock shares issued as a result of conversion of Preferred stock												4,288	9,183
Preferred stock, callable price, benchmark for consecutive days												$ 32.45
Minimum [Member] | 5.625% Convertible Perpetual Preferred Stock [Member]
Class of Stock [Line Items]
Stated conversion rate of common shares per preferred share							9.8578					10.0147	9.8578		10.0147
Preferred stock, consecutive days before stock can be called, out of 30 days												20 days
Maximum [Member] | 5.625% Convertible Perpetual Preferred Stock [Member]
Class of Stock [Line Items]
Stated conversion rate of common shares per preferred share							9.899					10.0579	9.899		10.0579
Preferred stock, consecutive days before stock can be called, out of 30 days												30 days
3.0% Senior Convertible Notes due 2018 [Member]
Class of Stock [Line Items]
Face value of notes																400,000,000
Debt instrument, stated interest rate																3.00%
Debt discount																63,400,000
Offering costs recorded as decrease in additional paid in capital																$ 1,400,000

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Concentrations of Credit Risk (Narrative) (Details) (Revenue [Member])	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Shell Trading Company [Member]
Concentration Risk [Line Items]
Percentage of Total Oil and Natural Gas Revenues	45.00%	35.00%	32.00%
Exxon Mobil Corporation [Member]
Concentration Risk [Line Items]
Percentage of Total Oil and Natural Gas Revenues	43.00%	37.00%	37.00%
JP Morgan [Member]
Concentration Risk [Line Items]
Percentage of Total Oil and Natural Gas Revenues		12.00%	18.00%

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Property and Equipment (Costs Related to Unproved Property Costs and Major Development Projects) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unevaluated Properties (acquisition costs)	$ 980,420
Wells in Progress (exploratory costs)	185,281
Oil and natural gas properties - full cost method of accounting, unevaluated properties	1,165,701
2011 and Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unevaluated Properties (acquisition costs)	38,289
Wells in Progress (exploratory costs)	122,724
Oil and natural gas properties - full cost method of accounting, unevaluated properties	161,013
2012 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Wells in Progress (exploratory costs)	89,611
Oil and natural gas properties - full cost method of accounting, unevaluated properties	89,611
2013 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unevaluated Properties (acquisition costs)	51,435
Wells in Progress (exploratory costs)	120,492
Oil and natural gas properties - full cost method of accounting, unevaluated properties	171,927
2014 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unevaluated Properties (acquisition costs)	890,696
Wells in Progress (exploratory costs)	(147,546)
Oil and natural gas properties - full cost method of accounting, unevaluated properties	$ 743,150

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Employee Benefit Plans (Narrative) (Details) (USD $)	12 Months Ended			1 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	Sep. 30, 2008
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Unrecognized compensation	$ 0
Total compensation expense recognized	24,244,000	21,276,000	50,463,000
Employee Stock Purchase Plan [Member]
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Stock issued	148,519	213,763	305,401
Discount from the lower of the common stock closing price on the first or last day of the period	15.00%
Stock Options [Member]
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Stock Options granted to certain officers				300,000
Stock Options granted to certain officers, exercise price				$ 17.50
Option vesting term				3 years
Stock options vested and exercised	100,000
Stock options vested and not exercised	200,000
Performance Units [Member]
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Share based payment awards, vesting period	3 years
Percentage of Time Based Performance units award out of the total performance units awarded	25.00%
Percentage of total shareholder return TSR Performance Based Units	75.00%
Initial stock price of units granted	$ 5.00
Performance based unit award, common stock paid, percentage	50.00%
Unvested stock units outstanding	6,780,358
Total compensation expense recognized	11,446,000	10,569,000	31,148,000
Restricted Stock Units (RSUs) [Member]
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Share based payment awards, vesting period	3 years
Unvested stock units outstanding	1,394,175
Total compensation expense recognized	$ 12,798,000	$ 10,707,000	$ 19,315,000
Time-Based Performance Units [Member]
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Grant date unit value of units granted	$ 5.00
Initial stock price of units granted	$ 21.72	$ 33.20	$ 34.40

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Income Taxes (Components of Income Tax Provision) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Current
United States	$ 3,641	$ 12,872
State			(53)
Total current	3,641	12,872	(53)
Deferred
United States	53,448	76,222	38,699
State		(2,461)
Total deferred	53,448	73,761	38,699
Total income tax provision	$ 57,089	$ 86,633	$ 38,646

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Earnings per Share (Calculation of Basic and Diluted Earnings per Share) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Earnings per Share [Abstract]
Net income	$ (1,815)		$ 7,292		$ 10,495		$ 43,139		$ 62,053		$ 40,436		$ 41,332		$ 18,260		$ 59,111	$ 162,081	$ 335,827
Preferred Stock Dividends	2,872		2,872		2,872		2,873		2,873		2,873		2,874		2,876		11,489	11,496	13,028
Induced Conversion of Preferred Stock																			6,068
Net Income (Loss) Available for Common Stockholders	$ (4,687)		$ 4,420		$ 7,623		$ 40,266		$ 59,180		$ 37,563		$ 38,458		$ 15,384		$ 47,622	$ 150,585	$ 316,731
Weighted average shares outstanding for basic EPS																	74,375,000	79,063,000	77,310,000
Add dilutive securities																	70,000	8,200,000	9,898,000
Weighted average shares outstanding for diluted EPS																	74,445,000	87,263,000	87,208,000
Basic	$ (0.06)	[1]	$ 0.06	[1]	$ 0.10	[1]	$ 0.53	[1]	$ 0.75	[1]	$ 0.47	[1]	$ 0.48	[1]	$ 0.19	[1]	$ 0.64	$ 1.90	$ 4.10
Diluted	$ (0.06)	[1]	$ 0.06	[1]	$ 0.10	[1]	$ 0.51	[1]	$ 0.72	[1]	$ 0.46	[1]	$ 0.47	[1]	$ 0.19	[1]	$ 0.64	$ 1.86	$ 3.85
Common stock, excluded from the diluted average shares due to an anti-dilutive effect																	8,336,700	5,474	4,821

[1] The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

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Income Taxes (Reconciliation of Statutory Income Tax Expense to Income Tax Provision) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Income Taxes [Abstract]
Income before income taxes	$ 116,200	$ 248,714	$ 374,473
Statutory rate	35.00%	35.00%	35.00%
Income tax expense computed at statutory rate	40,670	87,050	131,066
Reconciling items
Federal withholding obligation	10,343	10,343	10,371
Nontaxable foreign income	(2,133)	(8,214)	(9,655)
Change in valuation allowance		(59,853)	(26,996)
Tax return to provision adjustment to oil and natural gas properties		52,072
Release prior abandonment loss reserve			(7,106)
Debt cancelation - bond repurchase			(52,583)
State income taxes (benefit), net of federal tax benefit		(2,461)	(9,547)
Non-deductible executive compensation	2,725	5,616	7,400
Non-deductible transaction costs	1,853
Other - Net	3,631	2,080	(4,304)
Total income tax provision	$ 57,089	$ 86,633	$ 38,646

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Employee Benefit Plans (Compensation Expense Recognized) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense recognized	$ 24,244	$ 21,276	$ 50,463
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense recognized	12,798	10,707	19,315
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense recognized	$ 11,446	$ 10,569	$ 31,148

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Derivative Financial Instruments (Schedule of Cash Flow Hedging Relationship of Derivative Instruments) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)	$ 47,027	$ 31,051	$ (126,087)
Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)	(6,640)	(25,876)	(22,372)
Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)	6,339	881	(3,479)
Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)	(6,640)	(25,876)	(22,372)
Loss (Gain) on Derivative Financial Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)	6,339	881	(3,479)
Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)	$ 47,027	$ 31,051	$ (126,087)

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Fair Value of Financial Instruments

12 Months Ended

Jun. 30, 2014

Fair Value of Financial Instruments [Abstract]

Fair Value of Financial Instruments

Note 18 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

The carrying amounts approximate fair value for cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable due to the short-term nature or maturity of the instruments.

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 – Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Form 10-K.  

The fair values of our stock based units are based on period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model is used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on TSR Performance-Based Units valuation.

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

• Level 1 –  quoted prices in active markets for identical assets or liabilities.

• Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

• Level 3 – unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

During fiscal year 2014, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

	Level 1				Level 2
	As of June 30,				As of June 30,
	2014		2013		2014		2013
Assets:
Oil and natural gas derivatives					$	26,975	$	96,455
Liabilities:
Oil and natural gas derivatives					$	58,778	$	36,180
Restricted stock units	$	9,425	$	7,642
Time-based performance units		3,698		3,059
Total liabilities	$	13,123	$	10,701	$	58,778	$	36,180

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

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

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Acquisitions and Dispositions (Narrative) (Details) (USD $)	12 Months Ended			0 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	Jun. 28, 2013	Oct. 17, 2012 acre	Mar. 14, 2013	Feb. 01, 2013	Dec. 20, 2013	Nov. 07, 2012	Jan. 17, 2013	Mar. 07, 2014	Apr. 02, 2014	Jun. 03, 2014	Sep. 27, 2013
Restructuring Cost and Reserve [Line Items]
Debt instrument, stated interest rate	6.875%	6.875%
Reduction to the cost pool related to divestiture of business	$ 124,400,000
Estimated capital commitment to acquire seismic data	33,700,000
Exploration and development costs	788,676,000	816,105,000	570,670,000
West Delta Interests [Member]
Restructuring Cost and Reserve [Line Items]
Date of acquisition				Jun. 28, 2013
Cash value of purchase price				8,288,000
Gulf of Mexico Interests [Member]
Restructuring Cost and Reserve [Line Items]
Date of acquisition					Oct. 17, 2012
Gross acres covered in purchase agreement					5,000
Cash value of purchase price					32,817,000
Roda Interest [Member]
Restructuring Cost and Reserve [Line Items]
Date of acquisition						Mar. 14, 2013
Percentage of interest acquired in oil and gas properties						100.00%
Cash value of purchase price						32,662,000
Apache Joint Venture [Member]
Restructuring Cost and Reserve [Line Items]
Joint venture participation interest							25.00%
Seismic shoot phase term							2 years
Estimated capital commitment to acquire seismic data							37,500,000
Amount spent on seismic shoot		33,700,000
Exploration and development costs	28,100,000
Black Elk Interest [Member]
Restructuring Cost and Reserve [Line Items]
Date of acquisition								Dec. 20, 2013
Cash value of purchase price								10,404,000
Dynamic Interests [Member]
Restructuring Cost and Reserve [Line Items]
Date of acquisition									Nov. 07, 2012
Percentage of interest acquired in oil and gas properties									100.00%
Cash value of purchase price									7,233,000
McMoran Interest [Member]
Restructuring Cost and Reserve [Line Items]
Date of acquisition										Jan. 17, 2013
Cash value of purchase price										79,301,000
Walter Oil & Gas Corporation [Member]
Restructuring Cost and Reserve [Line Items]
Date of acquisition											Mar. 07, 2014
Cash value of purchase price											22,792,000
Energy XXI M21K LLC [Member]
Restructuring Cost and Reserve [Line Items]
Current borrowing base		25,000,000
Cash consideration from the sale of business												122,900,000
Gain (loss) on disposition of oil and gas property												0
Energy XXI GOM, LLC [Member]
Restructuring Cost and Reserve [Line Items]
Percentage of interest sold in oil and gas properties													100.00%
Cash consideration from the sale of business													230,000,000
Revolving Credit Facility [Member]
Restructuring Cost and Reserve [Line Items]
Current borrowing base														$ 850,000,000

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Commitments and Contingencies (Tables)

12 Months Ended

Jun. 30, 2014

Commitments and Contingencies [Abstract]

Future Minimum Lease Commitments Under Operating Leases

Future minimum lease commitments as of June 30, 2014 under the operating leases are as follows (in thousands):

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

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Supplemental Cash Flow Information (Non-cash Investing and Financing Activities) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Financing of insurance premiums	$ 21,967	$ 22,524	$ 22,211
Preferred stock dividends			(138)
Derivative instruments premium financing	11,257	18,231	16,259
Additions to property and equipment by recognizing asset retirement obligations	299,225	(9,820)	(45,998)
Repurchase of company common stock		13,997
Common Stock [Member]
Common stock issued for the EPL Acquisition, net	337,588
Treasury Stock [Member]
Common stock issued for the EPL Acquisition, net	154,717
Parent Company [Member] | Common Stock [Member]
Common stock issued for the EPL Acquisition, net	$ 315,394

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Supplementary Oil and Gas Information (Costs Related to Unproved Property Costs And Major Development Projects) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unevaluated Properties (acquisition costs)	$ 980,420
Wells in Progress (exploratory costs)	185,281
Oil and natural gas properties - full cost method of accounting, unevaluated properties	1,165,701
2011 and Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unevaluated Properties (acquisition costs)	38,289
Wells in Progress (exploratory costs)	122,724
Oil and natural gas properties - full cost method of accounting, unevaluated properties	161,013
2012 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Wells in Progress (exploratory costs)	89,611
Oil and natural gas properties - full cost method of accounting, unevaluated properties	89,611
2013 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unevaluated Properties (acquisition costs)	51,435
Wells in Progress (exploratory costs)	120,492
Oil and natural gas properties - full cost method of accounting, unevaluated properties	171,927
2014 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unevaluated Properties (acquisition costs)	890,696
Wells in Progress (exploratory costs)	(147,546)
Oil and natural gas properties - full cost method of accounting, unevaluated properties	$ 743,150

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Asset Retirement Obligations (Tables)

12 Months Ended

Jun. 30, 2014

Asset Retirement Obligations [Abstract]

Changes in Asset Retirement Obligations

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

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

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Acquisitions and Dispositions (Summary of Business Acquisition) (Details) (USD $)	0 Months Ended		12 Months Ended
	Jun. 03, 2014		Jun. 30, 2014	Jun. 03, 2013
Business Acquisition [Line Items]
Energy XXI Stock Issued	23,320,955
EPL Oil & Gas, Inc. [Member]
Business Acquisition [Line Items]
EPL Shares	39,900,000		4,700,000
Cash per share, acquiree				$ 39.00
Cash Paid	$ 1,012,000,000
Energy XXI Stock Issued	23,320,955
Cash value of Energy XXI stock issued	492,300,000
Total Purchase Price Paid to EPL	1,504,300,000
Cash Election [Member] | EPL Oil & Gas, Inc. [Member]
Business Acquisition [Line Items]
EPL Shares	30,600,000
Cash per share, acquiror	$ 25.92
Energy XXI Stock	0.5595
Cash Paid	792,600,000
Energy XXI Stock Issued	17,108,300
Energy XXI Stock Price on June 3, 2014	$ 21.11
Cash value of Energy XXI stock issued	361,200,000
Total Purchase Price Paid to EPL	1,153,800,000
Mixed Election [Member] | EPL Oil & Gas, Inc. [Member]
Business Acquisition [Line Items]
EPL Shares	7,400,000	[1]
Cash per share, acquiror	$ 25.35	[1]
Energy XXI Stock	0.584	[1]
Cash Paid	186,800,000	[1]
Energy XXI Stock Issued	4,303,700	[1]
Energy XXI Stock Price on June 3, 2014	$ 21.11	[1]
Cash value of Energy XXI stock issued	90,800,000	[1]
Total Purchase Price Paid to EPL	277,600,000	[1]
Stock Election [Member] | EPL Oil & Gas, Inc. [Member]
Business Acquisition [Line Items]
EPL Shares	1,100,000
Energy XXI Stock	1.669
Energy XXI Stock Issued	1,909,000
Energy XXI Stock Price on June 3, 2014	$ 21.11
Cash value of Energy XXI stock issued	40,300,000
Total Purchase Price Paid to EPL	40,300,000
Stock Option [Member] | EPL Oil & Gas, Inc. [Member]
Business Acquisition [Line Items]
EPL Shares	800,000
Cash per share, acquiree	$ 39.00
Cash Paid	32,600,000
Total Purchase Price Paid to EPL	$ 32,600,000

[1] Includes 4.7 million EPL shares, held by EPL stockholders and did not make an election prior to the May 30, 2014 election deadline.

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Derivative Financial Instruments (Narrative) (Details) (USD $)	12 Months Ended	52 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Derivative [Line Items]
Cash proceeds against certain hedge positions		$ 181,300,000
Deposits for collateral with counterparties	0
Amount expected to be reclassified from other comprehensive income to income	24,900,000
Net Of Tax
Derivative [Line Items]
Amount expected to be reclassified from other comprehensive income to income	16,200,000
Puts [Member]
Derivative [Line Items]
Deferred revenue			$ 2,200,000

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Long-Term Debt (High Yield Facilities) (Narrative) (Details) (USD $)	0 Months Ended			3 Months Ended	12 Months Ended	0 Months Ended			12 Months Ended	0 Months Ended
	Jun. 03, 2014	Apr. 18, 2014	May 27, 2014	Jun. 30, 2014	Jun. 30, 2014	Nov. 18, 2013	Sep. 26, 2013	Dec. 17, 2010	Jun. 30, 2013	Feb. 25, 2011	Jul. 08, 2011	Jul. 11, 2011	Sep. 30, 2012
Debt Instrument [Line Items]
Debt instrument, stated interest rate				6.875%	6.875%				6.875%
Face value of notes				$ 650,000,000	$ 650,000,000				650,000,000
8.25% Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	8.25%
Debt maturity date	Feb. 15, 2018
Face value of notes	510,000,000
Cash payment per $1,000 principal amount for which consents were delivered		2.50
Principal amount used to deliver consent		1,000
Aggregate principal amount for which valid consents were received	484,100,000
Debt instrument, fair value				545,700,000	545,700,000
6.875% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate			6.875%
Debt maturity date			Mar. 15, 2024
Face value of notes			650,000,000
Registration Statement to be effective in			365 days
Underwriting and direct offering costs				11,000,000
Senior unsecured notes, redemption term					Mar. 15, 2019
Debt instrument, redemption period				180 days
Percentage of aggregate principal amont of notes to remain outstanding				65.00%	65.00%
Redemption percentage in addition to whole premium and accrued and unpaid interest					100.00%
Percentage of senior notes exchanged for notes under indenture				106.875%
Maximum redemption rate				35.00%	35.00%
Debt instrument, fair value				663,000,000	663,000,000
3.0% Senior Convertible Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate						3.00%
Implied straight debt rate				6.75%	6.75%
Debt maturity date						Dec. 31, 2018
Face value of notes						400,000,000
Underwriting and direct offering costs						7,600,000
Initial conversion rate per $1,000 principal amount						24.7523
Principal amount used for conversion						1,000
Initial conversion price per share						$ 40.40
Consecutive trading-day conversion period						25 days
Debt discount						63,400,000
Debt amount after the discount						336,600,000
Percentage of unsecured senior note redemption price						100.00%
Debt instrument, fair value				396,800,000	396,800,000
7.50% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate							7.50%
Debt maturity date							Dec. 15, 2021
Face value of notes							500,000,000
Registration Statement to be effective in							270 days
Underwriting and direct offering costs					8,600,000
Senior unsecured notes, redemption term					Dec. 15, 2016
Percentage of unsecured senior note redemption price				107.50%	107.50%
Redemption percentage in addition to whole premium and accrued and unpaid interest					100.00%
Maximum redemption rate				35.00%	35.00%
Debt instrument, fair value				541,300,000	541,300,000
9.25% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate								9.25%	9.25%
Debt maturity date								Dec. 15, 2017
Face value of notes								750,000,000
Underwriting and direct offering costs					15,400,000
Starting date									Dec. 15, 2014
Latest date									Dec. 15, 2016
Percentage of call price of the par value of the note									104.625%
Remaining face value of notes								1,000,000
Senior unsecured notes, redemption term					Dec. 15, 2013
Percentage of unsecured senior note redemption price				109.25%	109.25%
Exchanged aggregate principal amount											749,000,000
Debt instrument, fair value				806,600,000	806,600,000
7.75% Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate									7.75%	7.75%
Debt maturity date										Jun. 15, 2019
Face value of notes										250,000,000
Underwriting and direct offering costs					3,100,000
Starting date					Jun. 15, 2015
Latest date					Jun. 15, 2017
Percentage of call price of the par value of the note				103.875%	103.875%
Senior unsecured notes, redemption term					Jun. 15, 2014
Percentage of unsecured senior note redemption price				107.75%	107.75%
Exchanged aggregate principal amount												250,000,000
Debt instrument, fair value				269,500,000	269,500,000
4.14% Promissory Note Due 2017 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate				4.14%	4.14%
Face value of notes													5,500,000
Debt instrument, monthly payment					52,000
Lump sum payments				3,300,000	3,300,000
Senior unsecured notes, redemption term					Oct. 30, 2017
Number of lump-sum payment					1
Derivative Instruments Premium Financing [Member]
Debt Instrument [Line Items]
Derivative instrument premium financing outstanding				21,000,000	21,000,000				24,700,000
Derivative instruments discount rate				2.50%	2.50%				2.50%
Change of Control [Member] | 6.875% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Percentage of unsecured senior note redemption price				101.00%	101.00%
Maximum [Member] | 9.25% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Maximum redemption rate				35.00%	35.00%
Maximum [Member] | 7.75% Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Maximum redemption rate				35.00%	35.00%
EPL Oil & Gas, Inc. [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate				8.25%	8.25%				8.25%
Face value of notes				$ 510,000,000	$ 510,000,000				510,000,000

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Supplementary Oil and Gas Information (Tables)

12 Months Ended

Jun. 30, 2014

Supplementary Oil and Gas Information [Abstract]

Costs Incurred for Oil and Gas Property Acquisition, Exploration and Development Activities

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

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

Costs Related to Unproved Property Costs and Major Development Projects

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

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

Estimated Quantities of Proved Domestic Oil and Gas Reserves and Changes in Quantities of Proved Developed And Undeveloped Reserves

Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and millions of cubic feet (“MMcf”) for each of the periods indicated were as follows:

	Oil	Natural Gas	Total
	(MBbls)	(MMcf)	(MBOE)
Proved reserves at June 30, 2011	77,206	236,316	116,592
Production	(11,172)	(29,824)	(16,143)
Extensions and discoveries	11,444	27,821	16,081
Revisions of previous estimates	9,098	(23,281)	5,217
Reclassification of proved undeveloped	(1,783)	(2,042)	(2,123)
Proved reserves at June 30, 2012	84,793	208,990	119,624
Production	(10,318)	(32,354)	(15,710)
Extensions and discoveries	40,690	40,714	47,476
Revisions of previous estimates	14,380	7,903	15,697
Reclassification of proved undeveloped	(1,123)	(1,755)	(1,416)
Purchases of reserves	5,225	45,623	12,829
Proved reserves at June 30, 2013	133,647	269,121	178,500
Production	(10,978)	(32,754)	(16,437)
Extensions and discoveries	17,141	19,703	20,424
Revisions of previous estimates	(3,567)	(29,822)	(8,537)
Sales of reserves	(4,159)	(3,378)	(4,722)
Purchases of reserves	53,305	141,986	76,970
Proved reserves at June 30, 2014	185,389	364,856	246,198
Proved developed reserves
June 30, 2011	59,234	134,024	81,572
June 30, 2012	63,308	110,310	81,693
June 30, 2013	80,223	175,623	109,493
June 30, 2014	112,789	222,916	149,942
Proved undeveloped reserves
June 30, 2011	17,972	102,292	35,020
June 30, 2012	21,485	98,680	37,931
June 30, 2013	53,424	93,498	69,007
June 30, 2014	72,600	141,940	96,256

Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2014, 2013 and 2012 are as follows (in thousands):

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

Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Applicable to Proved Crude Oil and Natural Gas Reserves

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

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

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Recent Accounting Pronouncements

12 Months Ended

Jun. 30, 2014

Recent Accounting Pronouncements [Abstract]

Recent Accounting Pronouncements

Note 2 — Recent Accounting Pronouncements

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We adopted ASU 2011-11 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

    In February 2013, the FASB issued Accounting Standards Update No.  2013-02: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”).   ASU 2013-02 updates ASU 2011-12 and requires companies to report information of significant changes in accumulated balances of each component of other comprehensive income  included in equity in one place.  Total changes in accumulated other comprehensive income by component can either be presented on the face of the financial statements or in the notes. ASU 2013-02 is effective for fiscal years and interim periods within those years beginning after December 15, 2012, with early adoption permitted. We adopted ASU 2013-02 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.  

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

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Long-Term Debt (Schedule of Long-Term Debt) (Details) (USD $)	0 Months Ended
	Dec. 17, 2010	Jun. 03, 2014	Feb. 25, 2011	Sep. 26, 2013	May 27, 2014	Nov. 18, 2013	Jun. 30, 2014		Jun. 30, 2013
Debt Instrument [Line Items]
Total debt							$ 3,759,644,000		$ 1,370,045,000
Less current maturities							15,020,000		19,554,000
Total long-term debt							3,744,624,000		1,350,491,000
Debt instrument, stated interest rate							6.875%		6.875%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Total debt							689,000,000		339,000,000
Derivative Instruments Premium Financing [Member]
Debt Instrument [Line Items]
Total debt							21,000,000		24,681,000
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Total debt							1,318,000		1,177,000
9.25% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Total debt							750,000,000		750,000,000
Debt instrument, stated interest rate	9.25%								9.25%
Debt maturity date	Dec. 15, 2017
8.25% Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Total debt							510,000,000
Debt instrument, stated interest rate		8.25%
Debt maturity date		Feb. 15, 2018
8.25% Senior Notes Due 2018 [Member] | Debt Premium [Member]
Debt Instrument [Line Items]
Total debt							40,566,000	[1]
7.75% Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Total debt							250,000,000		250,000,000
Debt instrument, stated interest rate			7.75%						7.75%
Debt maturity date			Jun. 15, 2019
7.50% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Total debt							500,000,000
Debt instrument, stated interest rate				7.50%
Debt maturity date				Dec. 15, 2021
6.875% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Total debt							650,000,000
Debt instrument, stated interest rate					6.875%
Debt maturity date					Mar. 15, 2024
3.0% Senior Convertible Notes due 2018 [Member]
Debt Instrument [Line Items]
Total debt							400,000,000
Debt discount						(63,400,000)
Debt instrument, stated interest rate						3.00%
Debt maturity date						Dec. 31, 2018
3.0% Senior Convertible Notes due 2018 [Member] | Original Issue Discount [Member]
Debt Instrument [Line Items]
Total debt							(57,014,000)
4.14% Promissory Note Due 2017 [Member]
Debt Instrument [Line Items]
Total debt							$ 4,774,000		$ 5,187,000
Debt instrument, stated interest rate							4.14%

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

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Income Taxes (Tables)

12 Months Ended

Jun. 30, 2014

Income Taxes [Abstract]

Income Before Income Tax

The amounts of income before income taxes attributable to U.S. and non-U.S. operations are as follows:

		Year Ended June 30,
		2014		2013		2012
		(In Thousands)
U.S. income	$	106,970	$	223,337	$	346,887
Non-U.S. income		9,230		25,377		27,586
Income before income taxes	$	116,200	$	248,714	$	374,473

Components of Income Tax Provision

The components of our income tax provision are as follows:

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

Reconciliation of Statutory Income Tax Expense to Income Tax Provision

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

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

Components of Deferred Taxes

The components of our deferred taxes are detailed in the table below:  

		June 30,
		2014		2013
		(In Thousands)
Deferred tax assets – current
Asset retirement obligation	$	44,182	$	-
Other		8,405		-
Total deferred tax assets - current		52,587		-
Deferred tax liabilities – current
Federal withholding obligation		-		(20,517)
Deferred tax assets – non current
Asset retirement obligation		61,412		100,697
Tax loss carryforwards on U.S. operations		448,404		386,899
Accrued interest expense		79,636		65,418
Deferred interest expense under IRC Sec. 162(j)		-		28,721
Employee benefit plans		-		6,213
Deferred state taxes		22,494		22,494
Derivative instruments and other		12,163
Other		11,471		6,860
Total deferred tax assets – non current		635,580		617,302
Deferred tax liabilities
Derivative instruments and other		-		(10,193)
Oil, natural gas properties and other property and equipment		(1,183,864)		(628,554)
Federal withholding obligation		(63,143)		(34,983)
Cancellation of debt		(9,680)		(9,680)
Employee benefit plans		(3,611)
Tax partnership activity		(53,826)		(52,202)
Total deferred tax liabilities – non current		(1,314,124)		(735,612)
Valuation allowance		(22,494)		(22,494)
Net deferred tax liability	$	(648,451)	$	(161,321)
Reflected in the accompanying balance sheet as
Current deferred tax asset (liability)	$	52,587	$	(20,517)
Non-current deferred tax liability	$	(701,038)	$	(140,804)

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Supplementary Oil and Gas Information

12 Months Ended

Jun. 30, 2014

Supplementary Oil and Gas Information [Abstract]

Supplementary Oil and Gas Information

Note 22 – Supplementary Oil and Gas Information – Unaudited

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

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

Oil and natural gas property costs excluded from the amortization base represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated.  We also allocate a portion of our acquisition costs to unevaluated properties based on fair value.  Costs are transferred to proved properties as the properties are evaluated or over the life of the reservoir. The wells in progress will be transferred into the amortization base once the results of the drilling activities are known.

We excluded from the amortization base the following costs related to unevaluated property costs and major development projects (in thousands):

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

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the U.S. are based on evaluations prepared by our reservoir engineers and audited by NSAI.  Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise that those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and millions of cubic feet (“MMcf”) for each of the periods indicated were as follows:

	Oil	Natural Gas	Total
	(MBbls)	(MMcf)	(MBOE)
Proved reserves at June 30, 2011	77,206	236,316	116,592
Production	(11,172)	(29,824)	(16,143)
Extensions and discoveries	11,444	27,821	16,081
Revisions of previous estimates	9,098	(23,281)	5,217
Reclassification of proved undeveloped	(1,783)	(2,042)	(2,123)
Proved reserves at June 30, 2012	84,793	208,990	119,624
Production	(10,318)	(32,354)	(15,710)
Extensions and discoveries	40,690	40,714	47,476
Revisions of previous estimates	14,380	7,903	15,697
Reclassification of proved undeveloped	(1,123)	(1,755)	(1,416)
Purchases of reserves	5,225	45,623	12,829
Proved reserves at June 30, 2013	133,647	269,121	178,500
Production	(10,978)	(32,754)	(16,437)
Extensions and discoveries	17,141	19,703	20,424
Revisions of previous estimates	(3,567)	(29,822)	(8,537)
Sales of reserves	(4,159)	(3,378)	(4,722)
Purchases of reserves	53,305	141,986	76,970
Proved reserves at June 30, 2014	185,389	364,856	246,198
Proved developed reserves
June 30, 2011	59,234	134,024	81,572
June 30, 2012	63,308	110,310	81,693
June 30, 2013	80,223	175,623	109,493
June 30, 2014	112,789	222,916	149,942
Proved undeveloped reserves
June 30, 2011	17,972	102,292	35,020
June 30, 2012	21,485	98,680	37,931
June 30, 2013	53,424	93,498	69,007
June 30, 2014	72,600	141,940	96,256

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

· Acquisitions of 52.3 MMBOE, primarily in the EPL Acquisition.   

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

Offset by:

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

· Divestiture of 4.7 MMBOE, and

· Production of 16.4 MMBOE

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

· Acquisitions of 24.6 MMBOE, primarily in the EPL Acquisition. 

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

Offset by

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

· Conversion of 6.6 MMBOE from proved undeveloped to proved developed reserves.   

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

We update and approve our reserves development plan on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total PUD reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors; including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves.  As scheduled in our long range plan, all of our proved undeveloped locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our report, with the exception of two.  They are locations to be sidetracked from existing wellbores which are still producing economically thus cannot be drilled until the proved developed producing zones deplete.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows as of June 30, 2014 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $96.75 per barrel of oil (calculated using the unweighted average first-day-of-the-month West Texas Intermediate posted prices during the 12-month period ending on June 30, 2014). The report forecasts crude oil and NGL production separately. The average realized adjusted product prices weighted by production over the remaining lives of the properties, used to determine future net revenues were $103.80 per barrel of oil and $42.10 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials.  The $103.80 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $96.75 per barrel (differential of $7.05 per barrel).

For natural gas, the average Henry Hub price used was $4.10 per MMBtu, prior to adjustments for energy content, transportation fees, and regional price differentials (calculated using the unweighted average first-day-of-the-month Henry Hub spot price). The average adjusted realized natural gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $4.14 per Mcf after adjusting for energy content, transportation fees, and regional price differentials. 

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2014, 2013 and 2012 are as follows (in thousands):

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

Changes in Standardized Measure of Discounted Future Net Cash Flows

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

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

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Selected Quarterly Financial Data

12 Months Ended

Jun. 30, 2014

Selected Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data

Note 21 — Selected Quarterly Financial Data – Unaudited

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

		Year Ended June 30, 2014
		Fourth		Third		Second		First
		Quarter		Quarter		Quarter		Quarter
Revenues	$	324,134	$	285,183	$	296,816	$	324,592
Operating income		54,677		64,801		61,502		99,431
Net income (loss)	$	(1,815)	$	7,292	$	10,495	$	43,139
Preferred stock dividends		2,872		2,872		2,872		2,873
Net income (loss) available for common stockholders	$	(4,687)	$	4,420	$	7,623	$	40,266
Net income (loss) per share attributable to common stockholders (1)
Basic	$	(0.06)	$	0.06	$	0.10	$	0.53
Diluted		(0.06)		0.06		0.10		0.51
		Year Ended June 30, 2013
		Fourth		Third		Second		First
		Quarter		Quarter		Quarter		Quarter
Revenues	$	314,325	$	303,774	$	320,519	$	270,227
Operating income		111,747		99,870		93,537		56,651
Net income	$	62,053	$	40,436	$	41,332	$	18,260
Preferred stock dividends		2,873		2,873		2,874		2,876
Net income available for common stockholders	$	59,180	$	37,563	$	38,458	$	15,384
Net income per share attributable to common stockholders (1)
Basic	$	0.75	$	0.47	$	0.48	$	0.19
Diluted		0.72		0.46		0.47		0.19

_______________________

(1)The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

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Supplementary Oil and Gas Information (Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Applicable to Proved Crude Oil and Natural Gas Reserves) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Supplementary Oil and Gas Information [Abstract]
Beginning of year	$ 4,481,522	$ 3,305,489	$ 2,561,393
Changes in prices and costs	(196,159)	(106,002)	855,382
Changes in quantities	(389,570)	635,562	153,537
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs	533,133	1,598,548	604,266
Purchases of reserves in place	1,735,957	480,111
Accretion of discount	614,964	429,745	333,748
Sales, net of production and gathering and transportation costs	(836,019)	(842,268)	(968,956)
Net change in income taxes	14,134	(676,158)	(215,873)
Changes in rate of production	(253,290)	(456,254)	(13,438)
Development costs incurred	247,865	125,925	24,519
Changes in abandonment costs and other	(5,012)	(13,176)	(29,089)
Net change	1,466,003	1,176,033	744,096
End of year	$ 5,947,525	$ 4,481,522	$ 3,305,489

XML

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

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Jun. 30, 2014

Fair Value of Financial Instruments [Abstract]

Fair Value of Financial Instruments

During fiscal year 2014, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

	Level 1				Level 2
	As of June 30,				As of June 30,
	2014		2013		2014		2013
Assets:
Oil and natural gas derivatives					$	26,975	$	96,455
Liabilities:
Oil and natural gas derivatives					$	58,778	$	36,180
Restricted stock units	$	9,425	$	7,642
Time-based performance units		3,698		3,059
Total liabilities	$	13,123	$	10,701	$	58,778	$	36,180

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

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

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Supplemental Guarantor Information

12 Months Ended

Jun. 30, 2014

Supplemental Guarantor Information [Abstract]

Supplemental Guarantor Information

Note 23 – Supplemental Guarantor Information

Our indirect, 100%-owned subsidiary, EGC, issued $650 million of its 6.875% Senior Notes due 2024 on May 27, 2014, $500 million of its 7.5% Senior Notes due 2021 on September 26, 2013, $750 million of its 9.25% Senior Notes due 2017 on December 17, 2010 and $250 million of its 7.75% Senior Notes due 2019 on February 25, 2011. 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 above 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 requires the issuer and guarantors to fileseparate financial statements. The Company meets the conditions in Rule 3-10 to report information about the assets, results of operations and comprehensive income (loss) and cash flows of the parent, subsidiary issuer and subsidiary guarantors using an alternative approach, which is to include in a footnote to the parent company's financial statements condensed consolidating financial information for the same periods as those presented for the parent company 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, the 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.

ENERGY XXI (BERMUDA) LIMITED

CONDENSED CONSOLIDATING BALANCE SHEET

(In Thousands)

	June 30, 2014
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$                135,703	$                3,723	$                    -	$                 6,380	$                        -	$         145,806
Accounts receivable
Oil and natural gas sales			127,773	50,990	(11,688)	167,075
Joint interest billings		1,833		11,065		12,898
Insurance and other	10	3,452	517	1,460	(1)	5,438
Prepaid expenses and other current assets	230	27,705	350	44,245		72,530
Deferred income taxes		27,424		25,163		52,587
Derivative financial instruments		1,425				1,425
Total Current Assets	135,943	65,562	128,640	139,303	(11,689)	457,759
Property and Equipment
Oil and natural gas properties			3,324,923	3,197,765	1,914	6,524,602
Other property and equipment				19,760		19,760
Total Property and Equipment, net	-	-	3,324,923	3,217,525	1,914	6,544,362
Other Assets
Goodwill				327,235		327,235
Derivative financial instruments		3,035				3,035
Equity investments	1,744,908	2,969,070		2,110,608	(6,783,943)	40,643
Intercompany receivables	102,489	1,627,931	-	60,562	(1,790,982)	-
Restricted cash			325	6,025		6,350
Other assets and debt issuance costs, net	178,299	42,155		7,940	(171,000)	57,394
Total Other Assets	2,025,696	4,642,191	325	2,512,370	(8,745,925)	434,657
Total Assets	$             2,161,639	$         4,707,753	$     3,453,888	$          5,869,198	$        (8,755,700)	$      7,436,778
LIABILITIES
Current Liabilities
Accounts payable	$                           -	$              64,533	$        150,909	$             212,157	$             (11,881)	$         415,718
Accrued liabilities	1,640	12,501	28,750	154,587	(63,952)	133,526
Notes payable		21,967				21,967
Deferred income taxes	19,185				(19,185)	-
Asset retirement obligations			39,819	39,830		79,649
Derivative financial instruments		5,517		26,440		31,957
Current maturities of long-term debt		14,093		927		15,020
Total Current Liabilities	20,825	118,611	219,478	433,941	(95,018)	697,837
Long-term debt, less current maturities	342,986	2,305,906		1,266,732	(171,000)	3,744,624
Deferred income taxes		211,055		470,798	19,185	701,038
Asset retirement obligations		49	247,272	232,864		480,185
Derivative financial instruments		2,166		2,140		4,306
Intercompany payables			1,736,240		(1,736,240)	-
Other liabilities				10,958		10,958
Total Liabilities	363,811	2,637,787	2,202,990	2,417,433	(1,983,073)	5,638,948
Stockholders’ Equity
Preferred stock
7.25% Convertible perpetual preferred stock						-
5.625% Convertible perpetual preferred stock	1					1
Common stock	468	1		10	(11)	468
Additional paid-in capital	1,837,462	2,092,439	273,129	3,580,004	(5,945,572)	1,837,462
Retained earnings (accumulated deficit)	(19,628)	(2,040)	977,769	(101,521)	(874,206)	(19,626)
Accumulated other comprehensive (loss) income	(20,475)	(20,434)		(26,728)	47,162	(20,475)
Total Stockholders’ Equity	1,797,828	2,069,966	1,250,898	3,451,765	(6,772,627)	1,797,830
Total Liabilities and Stockholders’ Equity	$             2,161,639	$         4,707,753	$     3,453,888	$          5,869,198	$        (8,755,700)	$      7,436,778

ENERGY XXI (BERMUDA) LIMITED

CONDENSED CONSOLIDATING BALANCE SHEET

(In Thousands)

	June 30, 2013
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$                   1,334	$                       -	$                    -	$                    137	$               (1,471)	$                   -
Accounts receivable
Oil and natural gas sales			150,007		(17,486)	132,521
Joint interest billings		9,505				9,505
Insurance and other		6,031	495	219		6,745
Prepaid expenses and other current assets	235	47,492	372	2,638	1	50,738
Derivative financial instruments		38,389				38,389
Total Current Assets	1,569	101,417	150,874	2,994	(18,956)	237,898
Property and Equipment
Oil and natural gas properties		16,553	3,272,952			3,289,505
Other property and equipment				17,003		17,003
Total Property and Equipment, net	-	16,553	3,272,952	17,003	-	3,306,508
Other Assets
Derivative financial instruments		21,926				21,926
Equity investments	1,259,247	1,066,803		1,544,751	(3,858,002)	12,799
Intercompany receivables	95,627	1,904,655		56,715	(2,056,997)	-
Deferred income taxes				29,884	(29,884)	-
Other assets and debt issuance costs, net	171,000	24,791		7,789	(171,000)	32,580
Total Other Assets	1,525,874	3,018,175	-	1,639,139	(6,115,883)	67,305
Total Assets	$            1,527,443	$        3,136,145	$     3,423,826	$          1,659,136	$        (6,134,839)	$    3,611,711
LIABILITIES
Current Liabilities
Accounts payable	$                          -	$           104,263	$        133,045	$                 1,258	$             (18,956)	$       219,610
Accrued liabilities	479	25,001	30,393	105,598	(56,279)	105,192
Notes payable	175	22,349				22,524
Deferred income taxes				20,517		20,517
Asset retirement obligations			29,500			29,500
Derivative financial instruments		40				40
Current maturities of long-term debt		18,838		716		19,554
Total Current Liabilities	654	170,491	192,938	128,089	(75,235)	416,937
Long-term debt, less current maturities	—	1,279,843		241,648	(171,000)	1,350,491
Deferred income taxes	16,883	153,805			(29,884)	140,804
Asset retirement obligations		50	258,268			258,318
Intercompany payables			1,913,195		(1,913,195)	-
Other liabilities				7,915		7,915
Total Liabilities	17,537	1,604,189	2,364,401	377,652	(2,189,314)	2,174,465
Stockholders’ Equity
Preferred stock
7.25% Convertible perpetual preferred stock						-
5.625% Convertible perpetual preferred stock	1					1
Common stock	396	1				397
Additional paid-in capital	1,512,310	1,426,351	369,195	1,370,648	(3,166,193)	1,512,311
Retained earnings (accumulated deficit)	(29,352)	79,304	690,231	(43,052)	(726,483)	(29,352)
Accumulated other comprehensive (loss) income	26,551	26,300	(1)	26,551	(52,849)	26,552
Treasury stock				(72,663)		(72,663)
Total Stockholders’ Equity	1,509,906	1,531,956	1,059,425	1,281,484	(3,945,525)	1,437,246
Total Liabilities and Stockholders’ Equity	$            1,527,443	$        3,136,145	$     3,423,826	$          1,659,136	$        (6,134,839)	$    3,611,711

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	For the Year Ended June 30, 2014
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Revenues
Crude oil sales	$                       -	$      (11,525)	$    1,046,263	$           56,485	$                        -	$     1,091,223
Natural gas sales		3,710	132,134	3,658		139,502
Total Revenues	-	(7,815)	1,178,397	60,143	-	1,230,725
Costs and Expenses
Lease operating		(325)	348,027	18,045		365,747
Production taxes		51	4,716	660		5,427
Gathering and transportation			23,532			23,532
Depreciation, depletion and amortization			399,086	26,340	(2,107)	423,319
Accretion of asset retirement obligations			28,161	2,022		30,183
General and administrative expense	7,380	1,134	81,380	6,508		96,402
Loss (gain) on derivative financial instruments		5,704				5,704
Total Costs and Expenses	7,380	6,564	884,902	53,575	(2,107)	950,314
Operating Income (Loss )	(7,380)	(14,379)	293,495	6,568	2,107	280,411
Other Income (Expense)
Income (loss) from equity method investees	66,995	296,279		92,191	(460,246)	(4,781)
Other income - net	19,923	1,954		17,808	(36,387)	3,298
Interest expense	(14,485)	(138,336)	(5,957)	(40,337)	36,387	(162,728)
Total Other Income (Expense)	72,433	159,897	(5,957)	69,662	(460,246)	(164,211)
Income (Loss) Before Income Taxes	65,053	145,518	287,538	76,230	(458,139)	116,200
Income Tax Expense	5,942	48,546		2,601		57,089
Net Income (Loss)	59,111	96,972	287,538	73,629	(458,139)	59,111
Preferred Stock Dividends	11,489				-	11,489
Net Income (Loss) Available for Common Stockholders	$          47,622	$      96,972	$       287,538	$           73,629	$         (458,139)	$          47,622
Comprehensive Income (Loss)
Net Income (Loss)	$          59,111	$      96,972	$       287,538	$           73,629	$         (458,139)	$          59,111
Other Comprehensive Income (Loss)	(47,027)	(38,523)		(8,504)	47,027	(47,027)
Comprehensive Income (Loss)	$          12,084	$      58,449	$       287,538	$           65,125	$         (411,112)	$          12,084

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	For the Year Ended June 30, 2013
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Revenues
Crude oil sales	$                       -	$       13,295	$    1,067,687	$                     -	$                        -	$     1,080,982
Natural gas sales		15,110	112,753			127,863
Total Revenues	-	28,405	1,180,440	-	-	1,208,845
Costs and Expenses
Lease operating		(3,249)	340,412			337,163
Production taxes		(658)	5,904			5,246
Gathering and transportation			24,168			24,168
Depreciation, depletion and amortization			372,252	3,972		376,224
Accretion of asset retirement obligations			30,885			30,885
General and administrative expense	7,439	2,820	61,089	250		71,598
Loss (gain) on derivative financial instruments		1,915		(159)		1,756
Total Costs and Expenses	7,439	828	834,710	4,063	-	847,040
Operating Income (Loss)	(7,439)	27,577	345,730	(4,063)	-	361,805
Other Income (Expense)
Income (loss) from equity method investees	156,516	333,039		176,979	(672,931)	(6,397)
Other income - net	18,584	1,849	12	17,833	(36,313)	1,965
Interest expense	(5)	(93,200)	(15,160)	(36,607)	36,313	(108,659)
Total Other Income (Expense)	175,095	241,688	(15,148)	158,205	(672,931)	(113,091)
Income (Loss) Before Income Taxes	167,656	269,265	330,582	154,142	(672,931)	248,714
Income Tax Expense (Benefit)	5,575	85,889		(4,831)		86,633
Net Income (Loss)	162,081	183,376	330,582	158,973	(672,931)	162,081
Preferred Stock Dividends	11,496					11,496
Net Income (Loss) Available for Common Stockholders	$        150,585	$     183,376	$       330,582	$      158,973	$         (672,931)	$        150,585
Comprehensive Income (Loss)
Net Income (Loss)	$        162,081	$     183,376	$       330,582	$      158,973	$         (672,931)	$        162,081
Other Comprehensive Income (Loss)	(31,051)	(32,985)		1,934	31,051	(31,051)
Comprehensive Income (Loss)	$        131,030	$     150,391	$       330,582	$      160,907	$         (641,880)	$        131,030

ENERGY XXI (BERMUDA) LIMITED
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(In Thousands)

	For the Year Ended June 30, 2012
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Revenues
Crude oil sales	$                       -	$           645	$    1,185,986	$                     -	$                        -	$     1,186,631
Natural gas sales		29,871	86,901			116,772
Total Revenues	-	30,516	1,272,887	-	-	1,303,403
Costs and Expenses
Lease operating		(343)	311,158			310,815
Production taxes		4	7,257			7,261
Gathering and transportation			16,371			16,371
Depreciation, depletion and amortization			364,281	3,182		367,463
Accretion of asset retirement obligations			39,161			39,161
General and administrative expense	6,990	3,476	75,603	207		86,276
Loss (gain) on derivative financial instruments		(7,261)		33		(7,228)
Total Costs and Expenses	6,990	(4,124)	813,831	3,422	-	820,119
Operating Income (Loss)	(6,990)	34,640	459,056	(3,422)	-	483,284
Other Income (Expense)
Income (loss) from equity method investees	331,110	459,057		315,146	(1,105,313)	-
Other income - net	16,722	1,191	1	17,828	(35,671)	71
Interest expense		(108,731)		(35,822)	35,671	(108,882)
Total Other Income (Expense)	347,832	351,517	1	297,152	(1,105,313)	(108,811)
Income (Loss) Before Income Taxes	340,842	386,157	459,057	293,730	(1,105,313)	374,473
Income Tax Expense (Benefit)	5,015	71,010		(37,379)		38,646
Net Income (Loss)	335,827	315,147	459,057	331,109	(1,105,313)	335,827
Induced Conversion of Preferred Stock	6,068					6,068
Preferred Stock Dividends	13,028					13,028
Net Income (Loss) Available for Common Stockholders	316,731	315,147	459,057	331,109	(1,105,313)	316,731
Comprehensive Income (Loss)
Net Income ( Loss)	$        335,827	$    315,147	$       459,057	$      331,109	$      (1,105,313)	$        335,827
Other Comprehensive Income (Loss), net	126,087	126,087			(126,087)	126,087
Comprehensive Income (Loss)	$        461,914	$    441,234	$       459,057	$      331,109	$      (1,231,400)	$        461,914

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

	For the Year Ended June 30, 2014
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Cash Flows From Operating Activities
Net income (Loss)	$               59,111	$        96,972	$        287,538	$             73,629	$            (458,139)	$           59,111
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization			399,086	26,340	(2,107)	423,319
Deferred income tax expense (benefit)	2,301	48,546		2,601		53,448
Change in derivative financial instruments
Other – net		(1,793)				(1,793)
Accretion of asset retirement obligations			28,161	2,022		30,183
Loss (income) from equity method investees	(66,995)	(296,279)		(92,191)	460,246	4,781
Amortization and write-off of debt issuance costs and other	7,219	6,555				13,774
Stock-based compensation	6,712				(1)	6,711
Changes in operating assets and liabilities
Accounts receivable	(10)	22,708	22,212	18,372	1	63,283
Prepaid expenses and other current assets	(18)	19,746	23	(13,733)	1	6,019
Settlement of asset retirement obligations			(57,391)			(57,391)
Accounts payable and accrued liabilities	(5,852)	87,745	(256,799)	1,284,956	(1,166,035)	(55,985)
Net Cash Provided by (Used in) Operating Activities	2,468	(15,800)	422,830	1,301,996	(1,166,034)	545,460
Cash Flows from Investing Activities
Acquisitions, net of cash acquired			(37,657)	(811,984)		(849,641)
Capital expenditures		16,746	(513,096)	(292,326)		(788,676)
Insurance payments received			1,983			1,983
Change in equity method investments				(34,294)		(34,294)
Proceeds from the sale of properties			126,265			126,265
Intercompany investment	(185,568)	(979,420)		(2,570)	1,167,558	-
Transfer to restricted cash			(325)			(325)
Other				113		113
Net Cash Provided by (Used in) Investing Activities	(185,568)	(962,674)	(422,830)	(1,141,061)	1,167,558	(1,544,575)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	3,994					3,994
Discount on convertible debt allocated to additional paid-in capital	63,432					63,432
Repurchase of company common stock	(30,824)			(153,439)		(184,263)
Dividends to shareholders - common	(34,680)					(34,680)
Dividends to shareholders - preferred	(11,489)					(11,489)
Proceeds from long-term debt	336,568	3,085,145		(840)		3,420,873
Payments on long-term debt	-	(2,079,072)		(413)		(2,079,485)
Debt issuance costs	(9,585)	(23,876)				(33,461)
Other	53				(53)	-
Net Cash Provided by (Used in) Financing Activities	317,469	982,197	-	(154,692)	(53)	1,144,921
Net Increase in Cash and Cash Equivalents	134,369	3,723	-	6,243	1,471	145,806
Cash and Cash Equivalents, beginning of year	1,334	-	-	137	(1,471)	-
Cash and Cash Equivalents, end of year	$             135,703	$          3,723	$                   -	$               6,380	$                         -	$         145,806

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

	For the Year Ended June 30, 2013
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Cash Flows From Operating Activities
Net income (Loss)	$             162,081	$      183,376	$        330,582	$            158,973	$            (672,931)	$          162,081
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization			372,252	3,972		376,224
Deferred income tax expense	(7,297)	85,889		(4,831)		73,761
Change in derivative financial instruments
Proceeds from sale of derivative instruments		635		125		760
Other – net		(27,357)		(159)		(27,516)
Accretion of asset retirement obligations			30,885			30,885
Loss (income) from equity method investees	(156,516)	(333,039)		(176,979)	672,931	6,397
Amortization and write-off of debt issuance costs and other		6,857		41		6,898
Stock-based compensation	3,504				1	3,505
Changes in operating assets and liabilities
Accounts receivable		14,422	(13,156)	424		1,690
Prepaid expenses and other current assets	8,772	2,865	760	103	(1)	12,499
Settlement of asset retirement obligations			(41,939)			(41,939)
Accounts payable and accrued liabilities	15,437	(284,637)	269,560	79,024	(46,481)	32,903
Net Cash Provided by (Used in) Operating Activities	25,981	(350,989)	948,944	60,693	(46,481)	638,148
Cash Flows from Investing Activities
Acquisitions, net of cash acquired			(161,164)			(161,164)
Capital expenditures		(17,144)	(787,774)	(11,187)		(816,105)
Change in equity method investments				(16,693)		(16,693)
Intercompany investment	(4,010)			(41,000)	45,010	-
Other			(6)	(35)		(41)
Net Cash Provided by (Used in) Investing Activities	(4,010)	(17,144)	(948,944)	(68,915)	45,010	(994,003)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	7,021			-		7,021
Repurchase of company common stock				(58,666)		(58,666)
Dividends to shareholders - common	(25,992)			-		(25,992)
Dividends to shareholders - preferred	(11,496)			-		(11,496)
Proceeds from long-term debt		1,571,061		5,490		1,576,551
Payments on long-term debt		(1,243,545)		(303)		(1,243,848)
Debt issuance costs		(4,777)		(28)		(4,805)
Other				3		3
Net Cash Provided by (Used in) Financing Activities	(30,467)	322,739	-	(53,504)	-	238,768
Net Decrease in Cash and Cash Equivalents	(8,496)	(45,394)	-	(61,726)	(1,471)	(117,087)
Cash and Cash Equivalents, beginning of year	9,830	45,394	-	61,863	-	117,087
Cash and Cash Equivalents, end of year	$                 1,334	$                  -	$                   -	$                   137	$                (1,471)	$                     -

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

	For the Year Ended June 30, 2012
	EXXI	EGC	Guarantor	Non-Guarantor	Reclassifications
	Bermuda Parent	Issuer	Subsidiaries	Subsidiaries	& Eliminations	Consolidated
Cash Flows From Operating Activities
Net income (Loss)	$             335,827	$      315,147	$        459,057	$            331,109	$         (1,105,313)	$          335,827
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization			364,281	3,182		367,463
Deferred income tax expense	5,015	71,011		(37,230)		38,796
Change in derivative financial instruments
Proceeds from sale of derivative instruments		66,522				66,522
Other – net		(52,155)				(52,155)
Accretion of asset retirement obligations		-	39,161			39,161
Loss (income) from equity method investees	(331,110)	(459,057)		(315,146)	1,105,313	-
Amortization and write-off of debt issuance costs and other		7,468		91		7,559
Stock-based compensation	11,702			58		11,760
Changes in operating assets and liabilities
Accounts receivable		(17,406)	12,984	(573)		(4,995)
Prepaid expenses and other current assets	(8,703)	(5,565)	892	(2,514)		(15,890)
Settlement of asset retirement obligations			(14,990)			(14,990)
Accounts payable and accrued liabilities	(15,919)	232,527	(298,228)	93,157	(5,081)	6,456
Net Cash Provided by (Used in) Operating Activities	(3,188)	158,492	563,157	72,134	(5,081)	785,514
Cash Flows from Investing Activities
Acquisitions, net of cash acquired			(6,401)			(6,401)
Capital expenditures			(565,978)	(4,692)		(570,670)
Insurance payments received			6,472			6,472
Change in equity method investments				(2,201)		(2,201)
Proceeds from the sale of properties			2,750			2,750
Intercompany investment and other	(1,000)			(3,624)	5,081	457
Net Cash Provided by (Used in) Investing Activities	(1,000)	-	(563,157)	(10,517)	5,081	(569,593)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	9,839					9,839
Discount on convertible debt allocated to additional paid-in capital						-
Conversion of preferred stock to common stock	(6,040)					(6,040)
Dividends to shareholders – preferred	(18,682)					(18,682)
Proceeds from long-term debt		896,717				896,717
Payments on long-term debt		(1,008,300)				(1,008,300)
Other	212	(859)		(128)		(775)
Net Cash Provided by (Used in) Financing Activities	(14,671)	(112,442)	-	(128)	-	(127,241)
Net Increase (Decrease) in Cash and Cash Equivalents	(18,859)	46,050	-	61,489	-	88,680
Cash and Cash Equivalents, beginning of year	28,689	(656)	-	374	-	28,407
Cash and Cash Equivalents, end of year	$                 9,830	$        45,394	$                   -	$              61,863	$                         -	$          117,087

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Schedule I Condensed Financial Statements

12 Months Ended

Jun. 30, 2014

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Financial Information of Parent Company Only

(2)  Financial Statement Schedules

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

ENERGY XXI (BERMUDA) LIMITED

CONDENSED BALANCE SHEETS

(In Thousands, except share information)

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

See accompanying Notes to Condensed Financial Statements

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

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

See accompanying Notes to Condensed Financial Statements

ENERGY XXI (BERMUDA) LIMITED
CONDENSED STATEMENTS OF CASH FLOWS

(In Thousands)

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

See accompanying Notes to Condensed Financial Statements

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Organization and Summary of Significant Accounting Policies

12 Months Ended

Jun. 30, 2014

Organization and Summary of Significant Accounting Policies

Note 1 — Organization and Summary of Significant Accounting Policies

Nature of Operations.   Energy XXI (Bermuda) Limited was incorporated in Bermuda on July 25, 2005. Headquartered in Houston, Texas, we are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico.

References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries.  We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported consolidated net income, consolidated stockholders’ equity or consolidated cash flows.

Use of Estimates.  The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such difference may be material.

Cash and Cash Equivalents.  We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents.

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

Accounts Receivable and Allowance for Doubtful Accounts.  Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts.  We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable.  Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.  As of June 30, 2014 and 2013, no allowance for doubtful accounts was necessary.

Oil and Natural Gas Properties.  We use the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. 

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated.  We also allocate a portion of our acquisition costs to unevaluated properties based on fair value.  Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict.

Depreciation, Depletion and Amortization.The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization.  The depreciable base of oil and natural gas properties is amortized using the unit-of-production method. 

Weather Based Insurance Linked Securities. We obtain Weather Based Insurance Linked Securities (“Securities”), to mitigate potential loss to our oil and natural gas properties from hurricanes in the Gulf of Mexico. These Securities provide for payments of negotiated amounts should a pre-defined category hurricane pass within specific pre-defined areas encompassing our oil and natural gas producing fields. Since these Securities were obtained to mitigate potential loss due to hurricanes in the Gulf of Mexico, the majority of the premiums associated with these Securities are charged to expense during the period associated with the hurricane season, typically June 1 to November 30. The amortization of insurance premiums for these Securities is recorded as a component of our lease operating expense. 

Other Property and Equipment.  Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets.  These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years.  Repairs and maintenance costs are expensed in the period incurred.

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

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

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

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

Derivative Instruments. We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Gains or losses resulting from transactions designated as cash flow hedges are recorded at market value and are recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of income as the physical production hedged by the contracts is delivered. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized directly in earnings.

The net cash flows related to any recognized gains or losses associated with cash flow hedges are reported as oil and natural gas revenue and presented in cash flow from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contract is delivered.

Debt Issuance Costs.  Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the scheduled maturity of the debt utilizing the straight-line method, which approximates the interest method.

Asset Retirement Obligations. Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

Common Stock. Refers to the $0.005 par value per share capital stock as designated in the Company’s Certificate of Incorporation.  Treasury Stock is accounted for using the cost method.

Revenue Recognition. We recognize oil and natural gas revenue under the entitlement method of accounting.  Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices.

General and Administrative Expense.  Under the full cost method of accounting, a portion of our general and administrative expense that is directly identified with our acquisition, exploration and development activities is capitalized as part of oil and natural gas properties.  These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to directly support those employees that are directly involved in acquisition, exploration and development activities.  The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities.  Our capitalized general and administrative expense directly related to our acquisition, exploration and development activities for the years ended June 30, 2014, 2013 and 2012 was $64.5 million, $37.6 million and $38.3 million, respectively.

Share-Based Compensation.Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award.  Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period.

Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate.

When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate any tax operating loss and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized in our consolidated financial statements.  At June 30, 2014 we maintained a $22.5 million valuation allowance against our net deferred tax assets due to our judgment that our existing State of Louisiana net operating loss (“NOL”) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years.  We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.  In light of our capital structure, U.S. withholding taxes attributable to interest due on loans from the Bermuda parent to the U.S. operating companies is provided as the interest accrues.  This U.S. withholding tax (at 30%) is due when the interest is actually paid, and may not be offset or reduced by U.S. operating activity; although the interest expense is generally deductible in the U.S. when paid, subject to certain other limitations. 

We adopted the provisions of ASC Topic 740-10 (formally known as FIN 48, addressing “Uncertain Tax Positions”) and applied this guidance as of July 1, 2007.  As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of ASC Topic 740-10 nor have we recorded any gross unrecognized tax benefit related to Uncertain Tax Positions. 

Earnings per Share. The Earnings per Share (“EPS”) amounts have been calculated based on the weighted-average number of shares of common stock outstanding for the year.  Diluted EPS reflects the potential dilution, using the treasury stock method.  The diluted EPS calculation includes shares of common stock from the assumed conversion of the Company’s redeemable preferred stock.

Parent Company [Member]

Organization and Summary of Significant Accounting Policies

Note 1 – Basis of Presentation

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

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

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Notes Receivable

12 Months Ended

Jun. 30, 2014

Notes Receivable [Abstract]

Notes Receivable

Note 2 – Notes Receivable

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

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Commitments and Contingencies (Future Minimum Lease Commitments Under Operating Leases) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014
Commitments and Contingencies [Abstract]
2015	$ 4,163
2016	4,717
2017	5,012
2018	4,176
2019	4,276
Thereafter	13,966
Total	$ 36,310

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Employee Benefit Plans (Tables)

12 Months Ended

Jun. 30, 2014

Employee Benefit Plans [Abstract]

Compensation Expense Recognized

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

		Year Ended June 30,
		2014		2013		2012
Restricted Stock Units	$	12,798	$	10,707	$	19,315
Performance Units		11,446		10,569		31,148
Total compensation expense recognized	$	24,244	$	21,276	$	50,463

Compensation Expense Recognized and Shares Issued Under Employee Stock Purchase Plan

The compensation expense recognized and shares issued under the Employee Stock Purchase Plan were as follows (in thousands, except for shares):

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

Defined Contribution Plans

The contributions under these plans were as follows (in thousands):

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

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Acquisitions and Dispositions (Purchase Price Allocations to the Assets Acquired and Liabilities Assumed) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended			0 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	Jun. 03, 2014		Oct. 17, 2012	Nov. 07, 2012	Jan. 17, 2013	Mar. 14, 2013	Dec. 20, 2013		Jun. 28, 2013	Mar. 07, 2014
Restructuring Cost and Reserve [Line Items]
Current assets (excluding deferred income taxes)	$ 457,759	$ 237,898
Other property and equipment	19,760	17,003
Current liabilities (excluding ARO)	(697,837)	(416,937)
ARO (Current and long-term)	(559,834)	(287,818)	(301,415)
Other long-term liabilities	(10,958)	(7,915)
Goodwill	327,235
U.S. statutory income tax rate	35.00%	35.00%	35.00%
Gulf of Mexico Interests [Member]
Restructuring Cost and Reserve [Line Items]
Oil and natural gas properties - evaluated						10,447
Oil and natural gas properties - unevaluated						27,721
ARO (Current and long-term)						(5,351)
Cash paid						32,817
Dynamic Interests [Member]
Restructuring Cost and Reserve [Line Items]
Oil and natural gas properties - evaluated							1,753
Oil and natural gas properties - unevaluated							6,571
ARO (Current and long-term)							(1,091)
Cash paid							7,233
McMoran Interest [Member]
Restructuring Cost and Reserve [Line Items]
Oil and natural gas properties - evaluated								62,499
Oil and natural gas properties - unevaluated								17,184
ARO (Current and long-term)								(382)
Cash paid								79,301
Roda Interest [Member]
Restructuring Cost and Reserve [Line Items]
Oil and natural gas properties - evaluated									32,777
ARO (Current and long-term)									(115)
Cash paid									32,662
Black Elk Interest [Member]
Restructuring Cost and Reserve [Line Items]
Oil and natural gas properties - evaluated										15,821
Oil and natural gas properties - unevaluated										6,586
ARO (Current and long-term)										(10,503)
Net working Capital										(1,500)	[1]
Cash paid										10,404
West Delta Interests [Member]
Restructuring Cost and Reserve [Line Items]
Oil and natural gas properties - evaluated												8,626
ARO (Current and long-term)												(338)
Cash paid												8,288
Walter Oil & Gas Corporation [Member]
Restructuring Cost and Reserve [Line Items]
Oil and natural gas properties - evaluated													23,497
ARO (Current and long-term)													(705)
Cash paid													22,792
EPL Oil & Gas, Inc. [Member]
Restructuring Cost and Reserve [Line Items]
Current assets (excluding deferred income taxes)				302,866
Oil and natural gas properties - evaluated				2,032,323	[2]
Oil and natural gas properties - unevaluated				901,782	[2]
Other property and equipment				7,787
Other assets				7,225
Current liabilities (excluding ARO)				(314,649)
ARO (Current and long-term)				(273,372)
Debt (current and long-term)				(1,026,407)
Deferred income taxes				(459,004)	[3]
Other long-term liabilities				(1,445)
Total fair value, excluding goodwill				1,177,106
Goodwill				327,235	[4]
Less cash acquired				206,075
Cash paid				1,504,300
Total purchase price				1,298,266
Estimated annual effective tax rate				37.00%
U.S. statutory income tax rate				35.00%
Weighted average statutory state tax rate				2.00%
EPL Oil & Gas, Inc. [Member] | Scenario, Previously Reported [Member]
Restructuring Cost and Reserve [Line Items]
Current assets (excluding deferred income taxes)				301,592
Oil and natural gas properties - evaluated				1,919,699	[2]
Oil and natural gas properties - unevaluated				41,896	[2]
Other property and equipment				7,787
Other assets				16,227
Current liabilities (excluding ARO)				(314,649)
ARO (Current and long-term)				(260,161)
Debt (current and long-term)				(973,440)
Deferred income taxes				(118,359)	[3]
Other long-term liabilities				(2,242)
Total fair value, excluding goodwill				618,350
Total purchase price				618,350
EPL Oil & Gas, Inc. [Member] | Fair Value Adjustment [Member]
Restructuring Cost and Reserve [Line Items]
Current assets (excluding deferred income taxes)				1,274
Oil and natural gas properties - evaluated				112,624	[2]
Oil and natural gas properties - unevaluated				859,886	[2]
Other assets				(9,002)
ARO (Current and long-term)				(13,211)
Debt (current and long-term)				(52,967)
Deferred income taxes				(340,645)	[3]
Other long-term liabilities				797
Total fair value, excluding goodwill				558,756
Goodwill				327,235	[4]
Total purchase price				$ 885,991

[1] Net working capital includes payables.

[2] EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.

[3] Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37 percent tax rate, which reflected the 35 percent federal statutory rate and a 2 percent weighted-average of the applicable statutory state tax rates (net of federal benefit).

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

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Derivative Financial Instruments (Components of AOCI Representing all of the Reclassifications out of AOCI) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Derivative Financial Instruments [Abstract]
Unrealized (gain) loss on derivatives at beginning of the year, before tax	$ (40,851)	$ (88,620)	$ 105,360
Unrealized change in fair value during the year, before tax	55,794	7,078	(224,919)
Ineffective portion reclassified to earnings during the year, before tax	6,339	881	(3,479)
Realized amounts reclassified to earnings during the year, before tax	10,215	39,810	34,418
Unrealized (gain) loss on derivatives at end of year, before tax	31,497	(40,851)	(88,620)
Unrealized (gain) loss on derivatives at beginning of year, after tax	(26,552)	(57,603)	68,484
Unrealized change in fair value during the year, after tax	36,266	4,601	(146,197)
Ineffective portion reclassified to earnings during the year, after tax	4,121	573	(2,261)
Realized amounts reclassified to earnings during the year, after tax	6,640	25,887	22,371
Unrealized (gain) loss on derivatives at end of year, after tax	$ 20,475	$ (26,552)	$ (57,603)

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Current Assets
Cash and cash equivalents	$ 145,806
Accounts receivable
Oil and natural gas sales	167,075	132,521
Joint interest billings	12,898	9,505
Insurance and other	5,438	6,745
Prepaid expenses and other current assets	72,530	50,738
Deferred income taxes	52,587
Derivative financial instruments	1,425	38,389
Total Current Assets	457,759	237,898
Property and Equipment
Oil and natural gas properties - full cost method of accounting, including $1,165.7 million and $422.6 million of unevaluated properties not being amortized at June 30, 2014 and 2013, respectively	6,524,602	3,289,505
Other property and equipment	19,760	17,003
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	6,544,362	3,306,508
Other Assets
Goodwill	327,235
Derivative financial instruments	3,035	21,926
Intercompany receivables
Equity investments	40,643	12,799
Restricted cash	6,350
Other assets and debt issuance costs, net of accumulated amortization	57,394	32,580
Total Other Assets	434,657	67,305
Total Assets	7,436,778	3,611,711
Current Liabilities
Accounts payable	415,718	219,610
Accrued liabilities	133,526	105,192
Notes payable	21,967	22,524
Deferred income taxes		20,517
Asset retirement obligations	79,649	29,500
Derivative financial instruments	31,957	40
Current maturities of long-term debt	15,020	19,554
Total Current Liabilities	697,837	416,937
Long-term debt, less current maturities	3,744,624	1,350,491
Deferred income taxes	701,038	140,804
Asset retirement obligations	480,185	258,318
Derivative financial instruments	4,306
Other liabilities	10,958	7,915
Total Liabilities	5,638,948	2,174,465
Commitments and Contingencies (Note 15)
Stockholders' Equity
Common stock, $0.005 par value, 200,000,000 shares authorized and 93,719,570 and 79,425,473 shares issued and 93,719,570 and 76,485,910 shares outstanding at June 30, 2014 and 2013, respectively	468	397
Additional paid-in capital	1,837,462	1,512,311
Accumulated deficit	(19,626)	(29,352)
Accumulated other comprehensive (loss) income, net of income taxes	(20,475)	26,552
Treasury stock, at cost, 2,938,900 shares at June 30, 2013	(170,266)	(72,663)
Total Stockholders' Equity	1,797,830	1,437,246
Total Liabilities and Stockholders' Equity	7,436,778	3,611,711
Parent Company [Member]
Current Assets
Cash and cash equivalents	135,703	1,334
Accounts receivable
Insurance and other	10
Prepaid expenses and other current assets	230	235
Total Current Assets	135,943	1,569
Other Assets
Intercompany receivables	102,489	95,627
Equity investments	1,744,908	1,259,247
Intercompany notes receivable	171,000	171,000
Other assets and debt issuance costs, net of accumulated amortization	7,299
Total Other Assets	2,025,696	1,525,874
Total Assets	2,161,639	1,527,443
Current Liabilities
Accrued liabilities	1,640	479
Notes payable		175
Deferred income taxes	19,185
Current liabilities	20,825	17,537
Total Current Liabilities	20,825	654
Long-term debt, less current maturities	342,986
Deferred income taxes		16,883
Total Liabilities	363,811	17,537
Stockholders' Equity
Common stock, $0.005 par value, 200,000,000 shares authorized and 93,719,570 and 79,425,473 shares issued and 93,719,570 and 76,485,910 shares outstanding at June 30, 2014 and 2013, respectively	468	396
Additional paid-in capital	1,837,462	1,512,310
Accumulated deficit	(19,628)	(29,352)
Accumulated other comprehensive (loss) income, net of income taxes	(20,475)	26,551
Total Stockholders' Equity	1,797,828	1,509,906
Total Liabilities and Stockholders' Equity	2,161,639	1,527,443
7.25% Convertible Perpetual Preferred Stock [Member]
Stockholders' Equity
Preferred stock
5.625% Convertible Perpetual Preferred Stock [Member]
Stockholders' Equity
Preferred stock	1	1
5.625% Convertible Perpetual Preferred Stock [Member] | Parent Company [Member]
Stockholders' Equity
Preferred stock	$ 1	$ 1

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Prepayments and Accrued Liabilities (Tables)

12 Months Ended

Jun. 30, 2014

Prepayments and Accrued Liabilities [Abstract]

Components of Prepayments and Accrued Liabilities

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

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

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Supplementary Oil and Gas Information (Costs Incurred for Oil And Gas Property Acquisition, Exploration And Development Activities) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Property acquisitions
Proved	$ 2,046,879	$ 108,825	$ 6,401
Unevaluated	924,882	52,339
Exploration costs	153,136	168,512	183,397
Development costs	$ 632,262	$ 633,868	$ 327,360

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Consolidated Statements of Stockholders' Equity (USD $) In Thousands	5.625% Convertible Perpetual Preferred Stock [Member]	Common Stock [Member]	Treasury Stock [Member]	Paid-in Capital [Member]	Accumulated (Deficit) [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total
Beginning Balance at Jun. 30, 2011	$ 1	$ 381		$ 1,479,959	$ (465,160)	$ (68,484)	$ 946,697
Common stock issued, net of direct costs		1		10,051			10,052
Common stock based compensation		2		11,758			11,760
Preferred stock converted to common		12		(12)
Common stock dividends					(5,516)		(5,516)
Preferred stock dividends					(13,028)		(13,028)
Preferred stock inducement				29	(6,068)		(6,039)
Comprehensive income					335,827	126,087	461,914
Ending Balance at Jun. 30, 2012	1	396		1,501,785	(153,945)	57,603	1,405,840
Common stock issued, net of direct costs		1		7,021			7,022
Common stock based compensation				3,505			3,505
Repurchase of company common stock			(72,663)				(72,663)
Common stock dividends					(25,992)		(25,992)
Preferred stock dividends					(11,496)		(11,496)
Comprehensive income					162,081	(31,051)	131,030
Ending Balance at Jun. 30, 2013	1	397		1,512,311	(29,352)	26,552	1,437,246
Beginning Balance at Mar. 31, 2013
Repurchase of company common stock			(72,663)				(72,663)
Preferred stock dividends							(2,873)
Ending Balance at Jun. 30, 2013	1	397	(72,663)	1,512,311	(29,352)	26,552	1,437,246
Common stock issued, net of direct costs		81		341,478			341,559
Common stock based compensation				6,711			6,711
Repurchase of company common stock			(170,266)				(170,266)
Treasury stock retired		(10)	52,966	(52,956)
Common stock reissued			189,963	(32,030)	(3,216)		154,717
Discount on convertible debt				61,948			61,948
Common stock dividends					(34,680)		(34,680)
Preferred stock dividends					(11,489)		(11,489)
Comprehensive income					59,111	(47,027)	12,084
Ending Balance at Jun. 30, 2014	$ 1	$ 468		$ 1,837,462	$ (19,626)	$ (20,475)	$ 1,797,830

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Quarterly Financial Data (Unaudited Quarterly Financial Data) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Selected Quarterly Financial Data [Abstract]
Revenues	$ 324,134		$ 285,183		$ 296,816		$ 324,592		$ 314,325		$ 303,774		$ 320,519		$ 270,227		$ 1,230,725	$ 1,208,845	$ 1,303,403
Operating Income (Loss)	54,677		64,801		61,502		99,431		111,747		99,870		93,537		56,651		280,411	361,805	483,284
Net income	(1,815)		7,292		10,495		43,139		62,053		40,436		41,332		18,260		59,111	162,081	335,827
Preferred Stock Dividends	2,872		2,872		2,872		2,873		2,873		2,873		2,874		2,876		11,489	11,496	13,028
Net income (loss) available for common stockholders	$ (4,687)		$ 4,420		$ 7,623		$ 40,266		$ 59,180		$ 37,563		$ 38,458		$ 15,384		$ 47,622	$ 150,585	$ 316,731
Net income (loss) per share attributable to common stockholders(1)
Basic	$ (0.06)	[1]	$ 0.06	[1]	$ 0.10	[1]	$ 0.53	[1]	$ 0.75	[1]	$ 0.47	[1]	$ 0.48	[1]	$ 0.19	[1]	$ 0.64	$ 1.90	$ 4.10
Diluted	$ (0.06)	[1]	$ 0.06	[1]	$ 0.10	[1]	$ 0.51	[1]	$ 0.72	[1]	$ 0.46	[1]	$ 0.47	[1]	$ 0.19	[1]	$ 0.64	$ 1.86	$ 3.85

[1] The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

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Equity Method Investments (Narrative) (Details) (USD $)	12 Months Ended		0 Months Ended			3 Months Ended	0 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Apr. 02, 2014	Sep. 17, 2013	Jul. 19, 2012	Sep. 30, 2013	Aug. 30, 2013	Jul. 25, 2013	Apr. 09, 2013	Jul. 09, 2013
Schedule of Equity Method Investments [Line Items]
Reduction to the cost pool related to divestiture of business	$ 124,400,000
Equity method investment	40,643,000	12,799,000
Equity (loss) income	(4,781,000)	(6,397,000)
Energy XXI M21K LLC [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of investments under the equity method	20.00%				20.00%
Purchase price of oil and gas properties					103,000,000
Share of remaining purchase price					16,000,000
Effective date of acquisition					Jan. 01, 2012
Amount of line of credit	100,000,000	100,000,000
Current borrowing base		25,000,000
Increase in current borrowing base				40,000,000
Cash consideration			122,900,000
Equity method investment	40,600,000
Equity (loss) income	(3,500,000)	(2,900,000)
Ping Energy XXI Limited [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of investments under the equity method	80.00%	49.00%
Equity (loss) income		(3,500,000)				(1,200,000)
LLOG Exploration Offshore [Member]
Schedule of Equity Method Investments [Line Items]
Purchase price of oil and gas properties							70,500,000	103,000,000
Share of remaining purchase price							16,200,000
Effective date of acquisition								Apr. 01, 2013
Closing date of acquisition							Aug. 30, 2013
Security deposit								10,300,000
Third Amendment [Member] | Energy XXI M21K LLC [Member]
Schedule of Equity Method Investments [Line Items]
Current borrowing base									$ 24,000,000	$ 20,000,000
Number of days until further borrowing capacity is reduced									90 days

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Supplementary Oil and Gas Information (Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Supplementary Oil and Gas Information [Abstract]
Future cash inflows	$ 20,162,506	$ 15,048,978	$ 10,009,119
Production costs	5,500,669	3,657,595	2,737,969
Development and abandonment costs	2,959,994	1,838,159	1,304,007
Income taxes	2,546,155	2,591,351	1,377,363
Future net cash flows	9,155,688	6,961,873	4,589,780
Ten percent annual discount for estimated timing of cash flows	3,208,163	2,480,351	1,284,291
Standardized measure of discounted future net cash flows	$ 5,947,525	$ 4,481,522	$ 3,305,489

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Property and Equipment (Tables)

12 Months Ended

Jun. 30, 2014

Property and Equipment [Abstract]

Schedule of Property and Equipment

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

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

Costs Related to Unproved Property Costs and Major Development Projects

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

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

Summary of Wells in Progress and Their Status

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

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

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Notes Payable (Narrative) (Details) (USD $)	1 Months Ended				0 Months Ended
	May 31, 2012	Jul. 31, 2012	Nov. 30, 2012	May 31, 2013	Jun. 03, 2014	Jun. 30, 2014	Jun. 30, 2013
Debt Instrument [Line Items]
Face value of note payable						$ 650,000,000	$ 650,000,000
Rate of interest on notes payable						6.875%	6.875%
AFCO Credit Corporation 1.556% [Member]
Debt Instrument [Line Items]
Face value of note payable	26,000,000
Rate of interest on notes payable	1.556%
Maturity date	Dec. 26, 2012
AFCO Credit Corporation 1.667% [Member]
Debt Instrument [Line Items]
Face value of note payable		3,600,000
Rate of interest on notes payable		1.667%
Maturity date		May 01, 2013
AFCO Credit Corporation 1.774% [Member]
Debt Instrument [Line Items]
Face value of note payable			600,000
Rate of interest on notes payable			1.774%
Maturity date			Oct. 23, 2013
AFCO Credit Corporation 1.623% [Member]
Debt Instrument [Line Items]
Face value of note payable				24,800,000
Rate of interest on notes payable				1.623%
Maturity date				Apr. 26, 2014
AFCO Credit Corporation 1.723% [Member]
Debt Instrument [Line Items]
Face value of note payable					22,000,000
Rate of interest on notes payable					1.723%
Debt outstanding						$ 22,000,000
Maturity date					May 03, 2015

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Commitments and Contingencies

12 Months Ended

Jun. 30, 2014

Commitments and Contingencies

Note 15 — Commitments and Contingencies

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

Litigation Related to the Merger

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

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

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

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

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

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

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

Guarantee.   EXXI M21K is the guarantor of a $100million line of credit entered into by M21K.  See Note 5 – Equity Method Investments of Notes to Consolidated Financial Statements in this Form 10-K. We have provided guarantees related to the payment of asset retirement obligations and other liabilities by M21K for the EP Energy, LLOG Exploration and Eugene Island 330 and South Marsh Island 128 properties acquisitions. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates.  See Note 13 – Related Party Transactions of Notes to Consolidated Financial Statements in this Form 10-K.

Drilling Rig Commitments.  The drilling rig commitments represent minimum future expenditures for drilling rig services.  The expenditures for drilling rig services will exceed such minimum amounts to the extent we utilize the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract. As of June 30, 2014, we have entered into nine drilling rig commitments:

1)  April 10, 2014 to October 27, 2014 at $54,448 per day

2)  January 1, 2014 to July 15, 2014 at $107,500 per day

3)  October 1, 2013 to September 1, 2014 at $125,000 per day

4)  March 10, 2014 to March 9, 2015 at $53,175 per day

5)  September 1, 2013 to August 31, 2014 at $140,000 per day

6)  February 15, 2014 to August 15, 2014 at $111,380 per day

7)  April 11, 2014 to September 15, 2014 at $112,000 per day

8)  July 1, 2014 to September 1, 2014 at $107,500 per day.

9)  September 1, 2014 to October 1, 2014 at $107,500 per day.

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

Parent Company [Member]

Commitments and Contingencies

Note 5 – Guarantee

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

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Long-Term Debt (Tables)

12 Months Ended

Jun. 30, 2014

Long-Term Debt [Abstract]

Schedule of Long-Term Debt

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

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

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

Maturities of Long-Term Debt

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

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

Interest Expense

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

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

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Supplementary Oil and Gas Information (Estimated Quantities of Proved Domestic Oil and Gas Reserves and Changes in Quantities of Proved Developed and Undeveloped Reserves) (Details)	12 Months Ended
	Jun. 30, 2014 MBoe	Jun. 30, 2013 MMBoe MBoe	Jun. 30, 2012 MBoe	Jun. 30, 2011 MBoe
Reserve Quantities [Line Items]
Beginning Balance	178,500	119,624	116,592
Production	(16,437)	(15,710)	(16,143)
Extensions and discoveries	20,424	47,476	16,081
Revisions of previous estimates	(8,537)	15,697	5,217
Reclassification of proved undeveloped		(1,416)	(2,123)
Purchases of reserves	76,970	12,829
Sales of reserves	(4,722)
Ending Balance	246,198	178,500	119,624
Proved developed reserves, MBOE	149,942	109,493	81,693	81,572
Proved undeveloped reserves, MBOE	96,256	69,007	37,931	35,020
Crude Oil [Member]
Reserve Quantities [Line Items]
Beginning Balance	133,647	84,793	77,206
Production	(10,978)	(10,318)	(11,172)
Extensions and discoveries	17,141	40,690	11,444
Revisions of previous estimates	(3,567)	14,380	9,098
Reclassification of proved undeveloped		(1,123)	(1,783)
Sales of reserves	(4,159)
Purchases of reserves	53,305	5,225
Ending Balance	185,389	133,647	84,793
Proved developed reserves	112,789	80,223	63,308	59,234
Proved undeveloped reserves	72,600	53,424	21,485	17,972
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning Balance	269,121	208,990	236,316
Production	(32,754)	(32,354)	(29,824)
Extensions and discoveries	19,703	40,714	27,821
Revisions of previous estimates	(29,822)	7,903	(23,281)
Reclassification of proved undeveloped		(1,755)	(2,042)
Sales of reserves	(3,378)
Purchases of reserves	141,986	45,623
Ending Balance	364,856	269,121	208,990
Proved developed reserves	222,916	175,623	110,310	134,024
Proved undeveloped reserves	141,940	93,498	98,680	102,292

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Concentrations of Credit Risk

12 Months Ended

Jun. 30, 2014

Concentration of Credit Risk [Abstract]

Concentrations of Credit Risk

Note 17 — Concentrations of Credit Risk

Major Customers.  We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices. 

Shell Trading Company (“Shell”) accounted for approximately 45%, 35% and 32% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively.  ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 43%, 37% and 37% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively.  J.P. Morgan Ventures Energy Corporation accounted for 12% and 18% of our total oil and natural gas revenues during the years ended June 30, 2013 and 2012, respectively.   We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Shell or ExxonMobil curtailed their purchases.

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

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

  Cash and Cash Equivalents.  We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions.  At times cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation.

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Derivative Financial Instruments (Schedule of Derivative Positions) (Details)	Jun. 30, 2014 MBbls
Oil-Brent-IPE [Member] | July 2014 - December 2014 [Member] | Three-Way Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	766
Sub Floor	69.00
Floor	89.00
Ceiling	124.99
Oil-Brent-IPE [Member] | July 2014 - December 2014 [Member] | Put Spread [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	431
Sub Floor	66.43
Floor	86.43
Oil-Brent-IPE [Member] | July 2014 - December 2014 [Member] | Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	368
Floor	90.00
Ceiling	108.38
Oil-Brent-IPE [Member] | January 2015 - December 2015 [Member] | Three-Way Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	3,650
Sub Floor	71.00
Floor	91.00
Ceiling	113.75
Oil-Brent-IPE [Member] | January 2015 - December 2015 [Member] | Swaps [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	548
Fixed Price	97.70
NYMEX-WTI [Member] | July 2014 - December 2014 [Member] | Three-Way Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	610
Sub Floor	70.00
Floor	90.00
Ceiling	137.20
NYMEX-WTI [Member] | July 2014 - December 2014 [Member] | Put [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	460
Floor	90.00
NYMEX-WTI [Member] | July 2014 - December 2014 [Member] | Put Spread [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	1,230
Sub Floor	70.00
Floor	90.00
NYMEX-WTI [Member] | July 2014 - December 2014 [Member] | Roll Swaps [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	2,295
Fixed Price	1.03
NYMEX-WTI [Member] | January 2015 - December 2015 [Member] | Put [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	1,813
Floor	88.76
NYMEX-WTI [Member] | January 2015 - December 2015 [Member] | Roll Swaps [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	3,180
Fixed Price	1.03
NYMEX-HH [Member] | July 2014 - December 2014 [Member] | Three-Way Collars [Member] | Natural Gas [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Natural Gas	8,187
Sub Floor	3.36
Floor	4.00
Ceiling	4.60
NYMEX-HH [Member] | July 2014 - December 2014 [Member] | Put Spread [Member] | Natural Gas [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Natural Gas	1,013
Sub Floor	3.25
Floor	4.00
NYMEX-HH [Member] | July 2014 - December 2014 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Natural Gas	920
Fixed Price	4.01
NYMEX-HH [Member] | January 2015 - December 2015 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Natural Gas	1,570
Fixed Price	4.31
Argus LLS [Member] | July 2014 - December 2014 [Member] | Swaps [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	1,614
Fixed Price	92.84
Argus LLS [Member] | January 2015 - December 2015 [Member] | Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	1,825
Floor	80.00
Ceiling	123.38

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Cash Flows From Operating Activities
Net income	$ 59,111	$ 162,081	$ 335,827
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	423,319	376,224	367,463
Deferred income tax expense	53,448	73,761	38,796
Change in derivative financial instruments
Proceeds from derivative instruments		760	66,522
Other - net	(1,793)	(27,516)	(52,155)
Accretion of asset retirement obligations	30,183	30,885	39,161
Income (loss) from equity method investees	4,781	6,397
Amortization and write-off of debt issuance costs and other	13,774	6,898	7,559
Stock-based compensation	6,711	3,505	11,760
Changes in operating assets and liabilities
Accounts receivable	63,283	1,690	(4,995)
Prepaid expenses and other current assets	6,019	12,499	(15,890)
Settlement of asset retirement obligations	(57,391)	(41,939)	(14,990)
Accounts payable and accrued liabilities	(55,985)	32,903	6,456
Net Cash Provided by Operating Activities	545,460	638,148	785,514
Cash Flows from Investing Activities
Acquisitions, net of cash acquired	(849,641)	(161,164)	(6,401)
Capital expenditures	(788,676)	(816,105)	(570,670)
Insurance payments received	1,983		6,472
Change in equity method investments	(34,294)	(16,693)	(2,201)
Proceeds from the sale of properties	126,265		2,750
Transfer to restricted cash	(325)
Other	113	(41)	457
Net Cash Used in Investing Activities	(1,544,575)	(994,003)	(569,593)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	3,994	7,021	9,839
Discount on convertible debt allocated to additional paid-in capital	63,432
Conversion of preferred stock to common stock			(6,040)
Repurchase of company common stock	(184,263)	(58,666)
Dividends to shareholders - common	(34,680)	(25,992)
Dividends to shareholders - preferred	(11,489)	(11,496)	(18,682)
Proceeds from long-term debt	3,420,873	1,576,551	896,717
Payments on long-term debt	(2,079,485)	(1,243,848)	(1,008,300)
Debt issuance costs	(33,461)	(4,805)
Other		3	(775)
Net Cash Provided by (Used in) Financing Activities	1,144,921	238,768	(127,241)
Net Increase (Decrease) in Cash and Cash Equivalents	145,806	(117,087)	88,680
Cash and Cash Equivalents, beginning of year		117,087	28,407
Cash and Cash Equivalents, end of year	145,806		117,087
Parent Company [Member]
Cash Flows From Operating Activities
Net income	59,111	162,081	335,827
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Deferred income tax expense	2,301	(7,297)	5,015
Change in derivative financial instruments
Income (loss) from equity method investees	(66,995)	(156,516)	(331,110)
Amortization and write-off of debt issuance costs and other	7,219
Stock-based compensation	9,013	(3,793)	16,717
Changes in operating assets and liabilities
Accounts receivable	(10)
Prepaid expenses and other current assets	(18)	8,772	(8,703)
Accounts payable and accrued liabilities	(5,852)	15,437	(15,919)
Changes in operating assets and liabilities	(5,880)	24,209	(24,622)
Net Cash Provided by Operating Activities	2,468	25,981	(3,188)
Cash Flows from Investing Activities
Change in equity method investments	(185,568)	(4,010)	(1,000)
Other			(1,000)
Net Cash Used in Investing Activities	(185,568)	(4,010)	(1,000)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	3,994	7,021	9,839
Discount on convertible debt allocated to additional paid-in capital	63,432
Conversion of preferred stock to common stock			(6,040)
Repurchase of company common stock	(30,824)
Dividends to shareholders - common	(34,680)	(25,992)
Dividends to shareholders - preferred	(11,489)	(11,496)	(18,682)
Dividends to shareholders	(46,169)	(37,488)	(18,682)
Proceeds from long-term debt	336,568
Debt issuance costs	(9,585)
Other	53		212
Net Cash Provided by (Used in) Financing Activities	317,469	(30,467)	(14,671)
Net Increase (Decrease) in Cash and Cash Equivalents	134,369	(8,496)	(18,859)
Cash and Cash Equivalents, beginning of year	1,334	9,830	28,689
Cash and Cash Equivalents, end of year	$ 135,703	$ 1,334	$ 9,830

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Oil and natural gas properties - full cost method of accounting, unevaluated properties	1,165.7	422.6
Preferred stock, par value	0.001	0.001
Preferred stock, shares authorized	7,500,000	7,500,000
Common stock, par value	0.005	0.005
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	93,719,570	79,425,473
Common stock, shares outstanding	93,719,570	76,485,910
Treasury stock, shares		2,938,900
7.25% Convertible Perpetual Preferred Stock [Member]
Preferred stock dividend rate	7.25%	7.25%
Preferred stock, shares issued	8,000	8,000
Preferred stock, shares outstanding	8,000	8,000
5.625% Convertible Perpetual Preferred Stock [Member]
Preferred stock dividend rate	5.625%	5.625%
Preferred stock, shares issued	812,760	813,188
Preferred stock, shares outstanding	812,760	813,188

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Stockholders' Equity

12 Months Ended

Jun. 30, 2014

Stockholders' Equity

Note 10 – Stockholders’ Equity

Common Stock

On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, our common stock was admitted for trading on The NASDAQ Global Select Market (“NASDAQ”). Our common stock trades on the NASDAQ and on the Alternative Investment Market of the London Stock Exchange (“AIM”) under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders.  We have 200,000,000 authorized common shares, par value of $0.005 per share.

We paid quarterly cash dividends of $0.07 per share to holders of our common stock on September 14, 2012,  December 14, 2012 and March 15, 2013 to shareholders of record on August 31, 2012,  November 30, 2012 and March 1, 2013, respectively, and paid quarterly cash dividends of $0.12 per share to holders of our common stock on June 14, 2013,  September 13, 2013,  December 13, 2013,  March 14, 2014 and June 13, 2014, to shareholders of record on May 31, 2013,  August 30, 2013,  November 29, 2013,  February 28, 2014 and May 30, 2014, respectively. 

On July 16, 2014, our Board of Directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of our common stock.  The quarterly dividend will be paid on September 12, 2014 to shareholders of record on August 29, 2014.

In May 2013, our Board of Directors approved a stock repurchase program authorizing us to repurchase up to $250 million in value of our common stock for an extended period of time, in one or more open market transactions. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity and other appropriate factors. The repurchase program does not obligate us to acquire any particular amount of common stock and may be modified or suspended at any time and could be terminated prior to completion. The repurchase program will be funded with cash on hand or borrowings on our revolving credit facility. Any repurchased shares of common stock will be retained at our subsidiary level, subject to transfer to the parent company where they may be retired.

Pursuant to the stock repurchase program approved by our Board of Directors in May 2013, during the year ended June 30, 2014, we incurred $94.2 million to repurchase 3,700,463 shares of our common stock at a weighted average price per share, excluding fees, of $25.45 and during the year ended June 30, 2013, we incurred $72.7 million to repurchase 2,938,900 shares of our common stock at a weighted average price per share, excluding fees, of $24.70.  As of June 30, 2014, $83.2 million remains available for repurchase under the share repurchase program. 

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

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

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

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

Preferred Stock

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

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

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

Conversion of Preferred Stock

During the year ended June 30, 2014, we canceled and converted a total of 428 shares of our 5.625% Preferred Stock into a total of 4,288 shares of common stock using a conversion rate ranging from 10.0147 to 10.0579 common shares per preferred share and during the year ended June 30, 2013, we canceled and converted a total of 929 shares of our 5.625% Preferred Stock into a total of 9,183 shares of common stock using a conversion rate ranging from 9.8578 to 9.899 common shares per preferred share.

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.

Parent Company [Member]

Stockholders' Equity

Note 4 – Stockholders’ Equity

On August 1, 2007, the Company’s common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, the Company’s common stock was admitted for trading on The NASDAQ Global Select Market (“NASDAQ”). The Company’s common stock trades on the NASDAQ and on the Alternative Investment Market of the London Stock Exchange (“AIM”) under the symbol “EXXI.” The Company’s shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. The Company has 200,000,000 authorized common shares, par value of $0.005 per share.

    We paid quarterly cash dividends of $0.07 per share to holders of our common stock on September 14, 2012, December 14, 2012 and March 15, 2013 to shareholders of record on August 31, 2012, November 30, 2012 and March 1, 2013, respectively, and paid quarterly cash dividends of $0.12 per share to holders of our common stock on June 14, 2013, September 13, 2013, December 13, 2013, March 14, 2014 and June 13, 2014, to shareholders of record on May 31, 2013, August 30, 2013, November 29, 2013, February 28, 2014 and May 30, 2014, respectively. 

    Pursuant to the stock repurchase program approved by our Board of Directors in May 2013, during the year ended June 30, 2014, we incurred $94.2 million to repurchase 3,700,463 shares of our common stock at a weighted average price per share, excluding fees, of $25.45 and during the year ended June 30, 2013, we incurred $72.7 million to repurchase 2,938,900 shares of our common stock at a weighted average price per share, excluding fees, of $24.70.  As of June 30, 2014, $83.2 million remains available for repurchase under the share repurchase program. 

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

Preferred Stock

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

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

Conversion of Preferred Stock

During the year ended June 30, 2014, we canceled and converted a total of 428 shares of our 5.625% Preferred Stock into a total of 4,288 shares of common stock using a conversion rate ranging from 10.0147 to 10.0579 common shares per preferred share and during the year ended June 30, 2013, we canceled and converted a total of 929 shares of our 5.625% Preferred Stock into a total of 9,183 shares of common stock using a conversion rate ranging from 9.8578 to 9.899 common shares per preferred share.

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

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Supplemental Guarantor Information (Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Revenues
Crude oil sales									$ 1,091,223	$ 1,080,982	$ 1,186,631
Natural gas sales									139,502	127,863	116,772
Total Revenues	324,134	285,183	296,816	324,592	314,325	303,774	320,519	270,227	1,230,725	1,208,845	1,303,403
Costs and Expenses
Lease operating									365,747	337,163	310,815
Production taxes									5,427	5,246	7,261
Gathering and transportation									23,532	24,168	16,371
Depreciation, depletion and amortization									423,319	376,224	367,463
Accretion of asset retirement obligations									30,183	30,885	39,161
General and administrative expense									96,402	71,598	86,276
Loss (gain) on derivative financial instruments									5,704	1,756	(7,228)
Total Costs and Expenses									950,314	847,040	820,119
Operating Income (Loss)	54,677	64,801	61,502	99,431	111,747	99,870	93,537	56,651	280,411	361,805	483,284
Other Income (Expense)
Income (loss) from equity method investees									(4,781)	(6,397)
Other income - net									3,298	1,965	71
Interest expense									(162,728)	(108,659)	(108,882)
Total Other Expense									(164,211)	(113,091)	(108,811)
Income Before Income Taxes									116,200	248,714	374,473
Income Tax Expense (Benefit)									57,089	86,633	38,646
Net Income	(1,815)	7,292	10,495	43,139	62,053	40,436	41,332	18,260	59,111	162,081	335,827
Induced Conversion of Preferred Stock											6,068
Preferred Stock Dividends	2,872	2,872	2,872	2,873	2,873	2,873	2,874	2,876	11,489	11,496	13,028
Net Income (Loss) Available for Common Stockholders	(4,687)	4,420	7,623	40,266	59,180	37,563	38,458	15,384	47,622	150,585	316,731
Other Comprehensive Income (Loss)									(47,027)	(31,051)	126,087
Comprehensive Income (Loss)									12,084	131,030	461,914
Parent Company [Member]
Costs and Expenses
General and administrative expense									7,380	7,439	6,990
Total Costs and Expenses									7,380	7,439	6,990
Operating Income (Loss)									(7,380)	(7,439)	(6,990)
Other Income (Expense)
Income (loss) from equity method investees									66,995	156,516	331,110
Other income - net									19,923	18,584	16,722
Interest expense									(14,485)	(5)
Total Other Expense									72,433	175,095	347,832
Income Before Income Taxes									65,053	167,656	340,842
Income Tax Expense (Benefit)									5,942	5,575	5,015
Net Income									59,111	162,081	335,827
Induced Conversion of Preferred Stock											6,068
Preferred Stock Dividends									11,489	11,496	13,028
Net Income (Loss) Available for Common Stockholders									47,622	150,585	316,731
Other Comprehensive Income (Loss)									(47,027)	(31,051)	126,087
Comprehensive Income (Loss)									12,084	131,030	461,914
Energy XXI Gulf Coast Inc [Member]
Revenues
Crude oil sales									(11,525)	13,295	645
Natural gas sales									3,710	15,110	29,871
Total Revenues									(7,815)	28,405	30,516
Costs and Expenses
Lease operating									(325)	(3,249)	(343)
Production taxes									51	(658)	4
General and administrative expense									1,134	2,820	3,476
Loss (gain) on derivative financial instruments									5,704	1,915	(7,261)
Total Costs and Expenses									6,564	828	(4,124)
Operating Income (Loss)									(14,379)	27,577	34,640
Other Income (Expense)
Income (loss) from equity method investees									296,279	333,039	459,057
Other income - net									1,954	1,849	1,191
Interest expense									(138,336)	(93,200)	(108,731)
Total Other Expense									159,897	241,688	351,517
Income Before Income Taxes									145,518	269,265	386,157
Income Tax Expense (Benefit)									48,546	85,889	71,010
Net Income									96,972	183,376	315,147
Net Income (Loss) Available for Common Stockholders									96,972	183,376	315,147
Other Comprehensive Income (Loss)									(38,523)	(32,985)	126,087
Comprehensive Income (Loss)									58,449	150,391	441,234
Guarantor Subsidiaries [Member]
Revenues
Crude oil sales									1,046,263	1,067,687	1,185,986
Natural gas sales									132,134	112,753	86,901
Total Revenues									1,178,397	1,180,440	1,272,887
Costs and Expenses
Lease operating									348,027	340,412	311,158
Production taxes									4,716	5,904	7,257
Gathering and transportation									23,532	24,168	16,371
Depreciation, depletion and amortization									399,086	372,252	364,281
Accretion of asset retirement obligations									28,161	30,885	39,161
General and administrative expense									81,380	61,089	75,603
Total Costs and Expenses									884,902	834,710	813,831
Operating Income (Loss)									293,495	345,730	459,056
Other Income (Expense)
Other income - net										12	1
Interest expense									(5,957)	(15,160)
Total Other Expense									(5,957)	(15,148)	1
Income Before Income Taxes									287,538	330,582	459,057
Net Income									287,538	330,582	459,057
Net Income (Loss) Available for Common Stockholders									287,538	330,582	459,057
Comprehensive Income (Loss)									287,538	330,582	459,057
Non-Guarantor Subsidiaries [Member]
Revenues
Crude oil sales									56,485
Natural gas sales									3,658
Total Revenues									60,143
Costs and Expenses
Lease operating									18,045
Production taxes									660
Depreciation, depletion and amortization									26,340	3,972	3,182
Accretion of asset retirement obligations									2,022
General and administrative expense									6,508	250	207
Loss (gain) on derivative financial instruments										(159)	33
Total Costs and Expenses									53,575	4,063	3,422
Operating Income (Loss)									6,568	(4,063)	(3,422)
Other Income (Expense)
Income (loss) from equity method investees									92,191	176,979	315,146
Other income - net									17,808	17,833	17,828
Interest expense									(40,337)	(36,607)	(35,822)
Total Other Expense									69,662	158,205	297,152
Income Before Income Taxes									76,230	154,142	293,730
Income Tax Expense (Benefit)									2,601	(4,831)	(37,379)
Net Income									73,629	158,973	331,109
Net Income (Loss) Available for Common Stockholders									73,629	158,973	331,109
Other Comprehensive Income (Loss)									(8,504)	1,934
Comprehensive Income (Loss)									65,125	160,907	331,109
Reclassifications & Eliminations [Member]
Costs and Expenses
Depreciation, depletion and amortization									(2,107)
Total Costs and Expenses									(2,107)
Operating Income (Loss)									2,107
Other Income (Expense)
Income (loss) from equity method investees									(460,246)	(672,931)	(1,105,313)
Other income - net									(36,387)	(36,313)	(35,671)
Interest expense									36,387	36,313	35,671
Total Other Expense									(460,246)	(672,931)	(1,105,313)
Income Before Income Taxes									(458,139)	(672,931)	(1,105,313)
Net Income									(458,139)	(672,931)	(1,105,313)
Net Income (Loss) Available for Common Stockholders									(458,139)	(672,931)	(1,105,313)
Other Comprehensive Income (Loss)									47,027	31,051	(126,087)
Comprehensive Income (Loss)									$ (411,112)	$ (641,880)	$ (1,231,400)

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Subsequent Events (Narrative) (Details) (USD $)	3 Months Ended								0 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Jul. 16, 2014
Subsequent Event [Line Items]
Cash dividend per share	$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.07	$ 0.07	$ 0.07
Subsequent Event [Member]
Subsequent Event [Line Items]
Cash dividend per share									$ 0.12

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Fair Value of Financial Instruments (Changes to Level 3 Financial Instruments) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Fair Value of Financial Instruments [Abstract]
Balance at beginning of period	$ 6,778	$ 22,855
Vested	(7,188)	(23,161)
Grants charged to income	7,320	7,084
Balance at end of period	$ 6,910	$ 6,778

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Document and Entity Information (USD $)	12 Months Ended
	Jun. 30, 2014	Jul. 31, 2014	Dec. 31, 2013
Document and Entity Information [Abstract]
Document Type	10-K/A
Amendment Flag	true
Document Period End Date	Jun. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	exxi
Entity Registrant Name	ENERGY XXI LTD
Entity Central Index Key	0001343719
Current Fiscal Year End Date	--06-30
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		93,865,377
Entity Public Float			$ 925,761,391
Amendment Description	This Amendment No. 1 ("Amendment No. 1") to the Annual Report of Energy XXI Ltd (the "Company") on Form 10-K for the fiscal year ended June 30, 2014 (the "Annual Report") is filed with the Securities and Exchange Commission (the "SEC") to amend Item 8 "Financial Statements and Supplementary Data" to include a new Note 23 – Supplemental Guarantor Information (the "Consolidating Footnote"), which includes condensed consolidating financial information for the Company, combined guarantor subsidiaries and combined non-guarantor subsidiaries in accordance with the requirements of Regulation S-X. The primary purpose of the Consolidating Footnote is to allow investors to determine the assets, results of operations and comprehensive income (loss) and cash flows of each of the consolidating groups. This Amendment solely modifies Part II, Item 8, of the Annual Report to include Note-23. All of the information in this Amendment No. 1 is as of August 25, 2014, the date the Company filed the Annual Report with the SEC. This Amendment No. 1 continues to speak as of the date of the Annual Report and does not reflect any subsequent information or events other than the amendment to Item 8 discussed above. Accordingly, this Amendment No. 1 should be read in conjunction with our filings made with the SEC subsequent to the filing of the Annual Report, including any amendments to those filings. Among other things, forward-looking statements made in the Annual Report have not been revised to reflect events, results or developments that occurred or facts that became known to us after the date of the Annual Report. The certifications pursuant to Section 302 and Section 906 of the Sarbanes-Oxley Act of 2002, filed as Exhibits 31.1, 31.2 and 32.1 to the Annual Report, have been re-executed and re-filed as of the date of this Amendment No. 1. The Company's management has considered whether the addition of the Consolidating Footnote to conform to the requirements of Rule 3-10 of Regulation S-X under the Exchange Act affects management's conclusion, set forth in the Annual Report, regarding the effectiveness, as of June 30, 2014, of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) and the Company's internal control over financial reporting, (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Management continues to believe that, as of June 30, 2014: • The Company's disclosure controls and procedures were functioning effectively to provide reasonable assurance that information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in SEC's rules and forms and (ii) accumulated and communicated to the Company's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure; and • The Company's internal control over financial reporting was effective based on the criteria on which it was evaluated, as described in the Annual Report. Management's Report on Internal Control over Financial Reporting is included in this Amendment No. 1.

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Supplemental Cash Flow Information

12 Months Ended

Jun. 30, 2014

Supplemental Cash Flow Information

Note 11 – Supplemental Cash Flow Information

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

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

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

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

Parent Company [Member]

Supplemental Cash Flow Information

Note 7 — Supplemental Cash Flow Information

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

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

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

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

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Related Party Transactions (Narrative) (Details) (USD $)	12 Months Ended		0 Months Ended		1 Months Ended	2 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 03, 2014	Apr. 02, 2014	Sep. 30, 2013	Aug. 31, 2013	Jun. 30, 2012	Jul. 19, 2012
Related Party Transaction [Line Items]
Asset retirement obligation	$ 559,834,000	$ 287,818,000					$ 301,415,000
Management fees, received	3,800,000	1,700,000
Energy XXI Gulf Coast Inc [Member]
Related Party Transaction [Line Items]
Percentage of interest sold in oil and gas properties			100.00%
Energy XXI M21K LLC [Member]
Related Party Transaction [Line Items]
Percentage of investments under the equity method	20.00%							20.00%
Amount of line of credit	100,000,000	100,000,000
Amount received from related party	3,100,000	1,900,000
Energy XXI M21K LLC [Member] | Payment Guarantee [Member]
Related Party Transaction [Line Items]
Due from related party, commitment period	3 years
Energy XXI M21K LLC [Member] | Payment Guarantee [Member] | Llog Exploration Offshore Limited Liability Company [Member]
Related Party Transaction [Line Items]
Asset retirement obligation	36,700,000
Due from related party	3,300,000
Energy XXI M21K LLC [Member] | Payment Guarantee [Member] | EP Energy Property [Member]
Related Party Transaction [Line Items]
Asset retirement obligation	65,000,000
Other Liabilities	1,800,000
Due from related party	6,300,000
Energy XXI M21K LLC [Member] | Payment Guarantee [Member] | Eugene Island 330 and South Marsh Island 128 [Member]
Related Party Transaction [Line Items]
Asset retirement obligation	18,600,000
Due from related party	$ 1,700,000
Energy XXI M21K LLC [Member] | Energy XXI Gulf Coast Inc [Member]
Related Party Transaction [Line Items]
Administrative assistance fee per BOE				0.98	1.15	0.83
Ping Energy XXI Limited [Member]
Related Party Transaction [Line Items]
Percentage of investments under the equity method	80.00%	49.00%

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Fair Value of Financial Instruments (Fair Value Level 1 and Level 2) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Fair Value, Inputs, Level 1 [Member]
Liabilities:
Fair value of liabilities	$ 13,123	$ 10,701
Fair Value, Inputs, Level 1 [Member] | Restricted Stock Units (RSUs) [Member]
Liabilities:
Fair value of liabilities	9,425	7,642
Fair Value, Inputs, Level 1 [Member] | Performance Units [Member]
Liabilities:
Fair value of liabilities	3,698	3,059
Fair Value, Inputs, Level 2 [Member]
Assets:
Fair value of assets	26,975	96,455
Liabilities:
Fair value of liabilities	58,778	36,180
Fair Value, Inputs, Level 2 [Member] | Oil and Natural Gas Derivatives [Member]
Liabilities:
Fair value of liabilities	$ 58,778	$ 36,180

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Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Revenues
Crude oil sales	$ 1,091,223	$ 1,080,982	$ 1,186,631
Natural gas sales	139,502	127,863	116,772
Total Revenues	1,230,725	1,208,845	1,303,403
Costs and Expenses
Lease operating	365,747	337,163	310,815
Production taxes	5,427	5,246	7,261
Gathering and transportation	23,532	24,168	16,371
Depreciation, depletion and amortization	423,319	376,224	367,463
Accretion of asset retirement obligations	30,183	30,885	39,161
General and administrative expense	96,402	71,598	86,276
Loss (gain) on derivative financial instruments	5,704	1,756	(7,228)
Total Costs and Expenses	950,314	847,040	820,119
Operating Income (Loss)	280,411	361,805	483,284
Other Income (Expense)
Income (loss) from equity method investees	(4,781)	(6,397)
Other income - net	3,298	1,965	71
Interest expense	(162,728)	(108,659)	(108,882)
Total Other Expense	(164,211)	(113,091)	(108,811)
Income Before Income Taxes	116,200	248,714	374,473
Income Tax Expense	57,089	86,633	38,646
Net Income	59,111	162,081	335,827
Induced Conversion of Preferred Stock			6,068
Preferred Stock Dividends	11,489	11,496	13,028
Net Income (Loss) Available for Common Stockholders	47,622	150,585	316,731
Earnings Per Share
Basic	$ 0.64	$ 1.90	$ 4.10
Diluted	$ 0.64	$ 1.86	$ 3.85
Weighted Average Number of Common Shares Outstanding
Basic	74,375	79,063	77,310
Diluted	74,445	87,263	87,208
Parent Company [Member]
Costs and Expenses
General and administrative expense	7,380	7,439	6,990
Total Costs and Expenses	7,380	7,439	6,990
Operating Income (Loss)	(7,380)	(7,439)	(6,990)
Other Income (Expense)
Income (loss) from equity method investees	66,995	156,516	331,110
Interest income	16,788	16,679	16,722
Other income - net	19,923	18,584	16,722
Interest expense	(14,485)	(5)
Guarantee income	3,135	1,900
Total Other Expense	72,433	175,095	347,832
Income Before Income Taxes	65,053	167,656	340,842
Income Tax Expense	5,942	5,575	5,015
Net Income	59,111	162,081	335,827
Induced Conversion of Preferred Stock			6,068
Preferred Stock Dividends	11,489	11,496	13,028
Net Income (Loss) Available for Common Stockholders	$ 47,622	$ 150,585	$ 316,731

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Equity Method Investments

12 Months Ended

Jun. 30, 2014

Equity Method Investments [Abstract]

Equity Method Investments

Note 5 - Equity Method Investments

20% interest in Energy XXI M21K, LLC

We own a 20% interest in EXXI M21K. EXXI M21K engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K, LLC (“M21K”).

On June 4, 2012, M21K entered into a Purchase and Sale Agreement (“PSA Agreement”) with EP Energy E&P Company, L.P. (“EP Energy”) to acquire interests in certain oil and natural gas fields owned by EP Energy. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was $103 million. The effective date of the acquisition was January 1, 2012.

   On July 19, 2012, M21K closed on the acquisition and we paid our share of the remaining purchase price of $16 million to EP Energy, prior to final adjustments. EXXI M21K is a guarantor of a $100 million first lien credit facility agreement entered into by M21K (“M21K First Lien Credit Agreement”). Simultaneous with the closing of the acquisition of assets from EP Energy, M21K entered into the First Amendment to the M21K First Lien Credit Agreement, which made technical changes to defined terms and hedging requirements, as well as established the borrowing base under the facility at $25 million.

On December 12, 2012, in conjunction with the name change from Natural Gas Partners Assets, LLC to M21K, LLC, M21K entered into the Second Amendment to the M21K First Lien Credit Agreement to reflect the name change and make technical changes to borrowing procedures.  

On April 9, 2013, M21K entered into the Third Amendment to the M21K First Lien Credit Agreement that made technical modification of a defined term and reduced the borrowing base to $24 million with a further reduction to $20 million within ninety days from the amendment date. 

On July 25, 2013 M21K entered into a PSA Agreement with LLOG Exploration Offshore, L.L.C. (“LLOG Exploration”) to acquire interests in certain oil and natural gas fields owned by LLOG Exploration. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was $103 million. The effective date of the acquisition was April 1, 2013.  In connection with this acquisition, M21K paid LLOG Exploration a performance deposit of $10.3 million.  On August 30, 2013, M21K closed on the acquisition and paid the remaining purchase price of $70.5 million to LLOG Exploration. Our share of the purchase price was approximately $16.2 million.    

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

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

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

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

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

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

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

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

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

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

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

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

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Property and Equipment

12 Months Ended

Jun. 30, 2014

Property and Equipment [Abstract]

Property and Equipment

Note 4 – Property and Equipment

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

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

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

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

The Company’s investment in unevaluated properties primarily relates to the unevaluated oil and gas properties acquired in oil and gas property acquisitions, exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. Costs associated with these unevaluated properties are transferred to evaluated properties upon the earlier of (i) when a determination is made whether there are any proved reserves related to the properties, or (ii) amortized over a period of time of not more than four years. 

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

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

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

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Income Taxes

12 Months Ended

Jun. 30, 2014

Income Taxes

Note 16 — Income Taxes

Our parent Company is a Bermuda company and it is generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure.

During the year ended June 30, 2009, we incurred a pre-tax impairment loss related to our oil and gas properties due to the steep decline in global energy prices over that same time period. This loss is not deductible for tax purposes until the impaired properties are depleted or disposed of.  As a result of this impairment, we have reported cumulative losses and remain marginally in an overall loss position.  Due to this previous loss position, coupled with volatility in energy prices (at the time) causing uncertainty as to operating results, we established a valuation allowance of $175.0 million during the year ended June 30, 2009. We have subsequently reduced this allowance by $152.5 million due principally to the reported pre-tax income in the subsequent years. This results in an ending valuation allowance of $22.5 million at June 30, 2014, which relates to certain State of Louisiana net operating loss carryovers that we do not currently believe, on a more-likely-than-not basis, are realizable due to our current focus on offshore operations. Management continues to monitor this situation closely, and the results from any change in judgment reflecting a change in the underlying facts will be reflected in the period of the factual change.

The amounts of income before income taxes attributable to U.S. and non-U.S. operations are as follows:

		Year Ended June 30,
		2014		2013		2012
		(In Thousands)
U.S. income	$	106,970	$	223,337	$	346,887
Non-U.S. income		9,230		25,377		27,586
Income before income taxes	$	116,200	$	248,714	$	374,473

The components of our income tax provision are as follows:

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

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

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

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below:  

		June 30,
		2014		2013
		(In Thousands)
Deferred tax assets – current
Asset retirement obligation	$	44,182	$	-
Other		8,405		-
Total deferred tax assets - current		52,587		-
Deferred tax liabilities – current
Federal withholding obligation		-		(20,517)
Deferred tax assets – non current
Asset retirement obligation		61,412		100,697
Tax loss carryforwards on U.S. operations		448,404		386,899
Accrued interest expense		79,636		65,418
Deferred interest expense under IRC Sec. 162(j)		-		28,721
Employee benefit plans		-		6,213
Deferred state taxes		22,494		22,494
Derivative instruments and other		12,163
Other		11,471		6,860
Total deferred tax assets – non current		635,580		617,302
Deferred tax liabilities
Derivative instruments and other		-		(10,193)
Oil, natural gas properties and other property and equipment		(1,183,864)		(628,554)
Federal withholding obligation		(63,143)		(34,983)
Cancellation of debt		(9,680)		(9,680)
Employee benefit plans		(3,611)
Tax partnership activity		(53,826)		(52,202)
Total deferred tax liabilities – non current		(1,314,124)		(735,612)
Valuation allowance		(22,494)		(22,494)
Net deferred tax liability	$	(648,451)	$	(161,321)
Reflected in the accompanying balance sheet as
Current deferred tax asset (liability)	$	52,587	$	(20,517)
Non-current deferred tax liability	$	(701,038)	$	(140,804)

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

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

Section 382 of the Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an “ownership change” and Code Section 383 provides similar rules for other tax attributes, e.g., capital losses. In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation by more than 50 percentage points over a three year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382 determined by multiplying the value of the Company’s stock at the time of the ownership change by the applicable long-term tax exempt rate (ranging between approximately 2.7% and 3.3%). Any unused annual limitation may be carried over to subsequent years. The amount of the limitation may, under certain circumstances, be increased by the built-in gains held by the Company at the time of the ownership change that are recognized in the five year period after the change. The Company experienced an ownership change on June 20, 2008, and a second ownership change on November 3, 2010. EPL similarly experienced an ownership change in 2009 and upon its acquisition in 2014. Based upon the Company’s determination of its annual limitation related to this ownership change, management believes that Section 382 should not otherwise limit the Company’s ability to utilize its federal or state NOLs or other attribute carryforwards during their applicable carryforward periods. Management will continue to monitor the potential impact of Code Sections 382 and 383 in future periods with respect to NOL and other tax carryforwards and will reassess realization of these carryforwards periodically.

We have not recorded any reserves for uncertain tax positions. We have a gross unrecorded noncurrent deferred tax asset of $13.2 million representing a percentage depletion carryover resulting from the EPL acquisition.

We filed our initial tax returns for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 through 2013.  The tax years ended June 30, 2011 through 2014 remain open to examination under the applicable statute of limitations in the U.S. in which the Company and its subsidiaries file income tax returns.  However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not begin to run until the year the attribute is utilized.  In some instances, state statutes of limitations are longer than those under U.S. federal tax law.  On May 13, 2014, the U.S. Internal Revenue Service (“IRS”) notified the Company of their intent to examine the Company’s U.S. federal income tax return (Form 1120) for the year ended June 30, 2013. The resolution of unagreed tax issues cannot be predicted with absolute certainty, and differences between what has been recorded and the eventual outcomes may occur.  The Company believes that it has adequately provided for income taxes and any related interest and penalties for all open tax years.

We have historically paid no significant US cash income taxes due to the election to expense intangible drilling costs and the presence of our NOLs. However, if current income trends continue, we could be responsible for making cash tax payments in fiscal 2015 from application of the alternative minimum tax (AMT) under current law. We presently do not expect to make any cash income tax payments during the upcoming fiscal year. If any such AMT payments were required, we believe that they would be recoverable against future regular income taxes due, with no expiration period.  As such, we do not believe that any AMT payments would have a negative impact on earnings. We revise our ongoing estimated AMT obligation each quarter during the year.

   We paid $3.6 million cash in U.S. withholding taxes during the year as a result of payments of interest on indebtedness and management fees to our Bermuda entities.  These withholding taxes are presented as separate line items in the effective tax rate reconciliation and payments expected in the coming fiscal year are presented as a current federal withholding obligation in the balance sheet.

Parent Company [Member]

Income Taxes

Note 6 – Income Taxes

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

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Employee Benefit Plans

12 Months Ended

Jun. 30, 2014

Employee Benefit Plans [Abstract]

Employee Benefit Plans

Note 12 – Employee Benefit Plans

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

Performance Units

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

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

TSR Performance-Based Units.  For each TSR Performance-Based Unit, the executive will receive a cash payment equal to the grant date unit value of $5.00 multiplied by (a) the cumulative percentage change in the price per share of the Company’s common stock from the date on which the TSR Performance-Based Units were granted (the “Total Shareholder Return”) and (b) the TSR Unit Number Modifier.

In addition, the employee may have the opportunity to earn additional compensation based on the Company’s Total Shareholder Return at the end of the third Performance Period.

At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due employees will be settled in either common shares or cash. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable. Historically, we have settled all vesting awards in cash.  The July 21, 2014 vesting of the July 21, 2013 and 2012 Performance Unit awards were settled50% in common stock and future vesting of the Performance Units may be settled in stock at the discretion of our board of directors.  

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

		Year Ended June 30,
		2014		2013		2012
Restricted Stock Units	$	12,798	$	10,707	$	19,315
Performance Units		11,446		10,569		31,148
Total compensation expense recognized	$	24,244	$	21,276	$	50,463

As of June 30, 2014, we have1,394,175 unvested Restricted Stock Units and6,780,358 unvested Performance Based Units.

Stock Purchase Plan

Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of our common stock that have either been purchased by us on the open market or are newly issued by us. During the years ended June 30, 2014, 2013 and 2012, we issued148,519 shares,213,763 shares and 305,401 shares, respectively, under the 2008 Purchase Plan.

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period. The current offering period is from July 1, 2014 to December 31, 2014. We use the Black-Scholes Model to determine fair value, which incorporates assumptions to value stock-based awards. The shares issuable under the Employee Stock Purchase Plan are included in calculating diluted earnings per share, if dilutive. As of June 30, 2014 there was no unrecognized compensation. The compensation expense recognized and shares issued under the Employee Stock Purchase Plan were as follows (in thousands, except for shares):

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

Stock Options

In September 2008, our Board of Directors granted 300,000 stock options to certain officers of the Company. These options to purchase our common stock were granted with an exercise price of $17.50 per share. These options vested over a three year period and may be exercised any time prior to September 10, 2018. We utilized the Black-Scholes model to determine the fair value of these stock options.  As of June  30, 2014,  100,000 of the vested options have been exercised and the remaining 200,000 vested options have not been exercised.

Defined Contribution Plans

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

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

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Income Taxes (Narrative) (Details) (USD $)	12 Months Ended				0 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2010	Jun. 03, 2014	Jun. 30, 2009
Income Taxes [Line Items]
U.S. statutory income tax rate	35.00%	35.00%	35.00%
U.S. withholding tax rate on any interest payments	30.00%
Valuation allowance	$ 22,494,000	$ 22,494,000				$ 175,000,000
Decrease in valuation allowance				152,500,000
Decrease in deferred tax liabilities	25,300,000
Derivative instruments and other	12,163,000
Net Operating Loss carry forward, Federal	1,300,000,000
Net Operating Loss carry forward, State	743,000,000
Ownership change description	Section 382 of the Code ("Section 382") imposes limitations on a corporation's ability to utilize its NOLs if it experiences an "ownership change" and Code Section 383 provides similar rules for other tax attributes, e.g., capital losses. In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation by more than 50 percentage points over a three year period.
Withholding taxes related to payments of interest and management fees	3,600,000
Total deferred tax liabilities - non current	1,314,124,000	735,612,000
Deferred tax asset gross	13,200,000
Other Comprehensive Income (Loss) [Member]
Income Taxes [Line Items]
Derivative instruments and other	7,700,000
Minimum [Member]
Income Taxes [Line Items]
Income tax NOLs expiration year	Dec. 31, 2026
Long term tax exempt rate	2.70%
Tax years remain open for examination		2011
Maximum [Member]
Income Taxes [Line Items]
Income tax NOLs expiration year	Dec. 31, 2034
Long term tax exempt rate	3.30%
Tax years remain open for examination	2014
EPL Oil & Gas, Inc. [Member]
Income Taxes [Line Items]
Estimated annual effective tax rate					37.00%
U.S. statutory income tax rate					35.00%
Total deferred tax liabilities - non current	$ 459,000,000

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Asset Retirement Obligations

12 Months Ended

Jun. 30, 2014

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

Note 8 – Asset Retirement Obligations

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

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

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Long-Term Debt (Revolving Credit Facility) (Narrative) (Details) (Revolving Credit Facility [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Sep. 27, 2013	Apr. 07, 2014	Jun. 03, 2014
Debt Instrument [Line Items]
Leverage ratio	3.6
Current borrowing base		$ 850.0
Letter of credit	225.7
Credit facility outstanding	689.0
Minimum [Member]
Debt Instrument [Line Items]
Percentage of secured mortgage	85.00%
Leverage ratio	3.5
Maximum [Member]
Debt Instrument [Line Items]
Current ratio	1.0
Interest rate coverage ratio	3.0
Fourth Amendment as of April 9, 2013 [Member]
Debt Instrument [Line Items]
Amount of line of credit	1,700.0
Debt maturity date	Apr. 09, 2018
Sixth Amendment as of September 27, 2013 [Member]
Debt Instrument [Line Items]
Current borrowing base	1,087.5
Seventh Amendment as of April 7, 2014 [Member]
Debt Instrument [Line Items]
Current borrowing base	1,200.0
Unsecured indebtedness, maximum			1,000
Unsecured indebtedness reduction aggregate, reduction percentage			25.00%
Eighth Amendment as of June 3, 2014 [Member]
Debt Instrument [Line Items]
Current borrowing base	1,500.0
Unsecured indebtedness, maximum	1,000
Unsecured indebtedness reduction aggregate, reduction percentage	25.00%
Market Rate Applies [Member] | Minimum [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Applicable margin above LIBOR or the base rate	1.75%
Market Rate Applies [Member] | Minimum [Member] | Federal Funds Rate [Member]
Debt Instrument [Line Items]
Applicable margin above LIBOR or the base rate	0.75%
Market Rate Applies [Member] | Maximum [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Applicable margin above LIBOR or the base rate	2.75%
Market Rate Applies [Member] | Maximum [Member] | Federal Funds Rate [Member]
Debt Instrument [Line Items]
Applicable margin above LIBOR or the base rate	1.75%
Leverage Ratio Exceeds , Condition of Waiver [Member] | Maximum [Member]
Debt Instrument [Line Items]
Leverage ratio	4.25
EPL Oil & Gas, Inc. [Member] | Eighth Amendment as of June 3, 2014 [Member]
Debt Instrument [Line Items]
Amount of line of credit				475.0
Credit facility outstanding				$ 475.0

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Long-Term Debt

12 Months Ended

Jun. 30, 2014

Long-Term Debt

Note 6 – Long-Term Debt

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

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

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

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

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

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by EGC, in May 2011 and underwent its Eighth Amendment on June 3, 2014 as noted below. This facility, as amended, has lender commitments of $1.7 billion and matures on April 9, 2018, provided that the facility will mature immediately if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Borrowings are limited to a borrowing base of $1.5 billion, which is based on oil and natural gas reserve values which are re-determined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, EGC is allowed to pay us a limited amount of distributions, subject to certain terms and conditions. The First Lien Credit Agreement, as amended, requires the consolidated EGC to maintain certain financial covenants. Specifically, EGC may not permit the following under First Lien Credit Agreement: (a) EGC’s total leverage ratio to be more than 3.5 to 1.0, (b) EGC’s interest coverage ratio to be less than 3.0 to 1.0, and (c) EGC’s current ratio (in each case as defined in the First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, EGC is subject to various other covenants including, but not limited to, those limiting its ability to declare and pay dividends or other payments, its ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability. 

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

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

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

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

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

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

High Yield Facilities

8.25% Senior Notes Due 2018

On June 3, 2014, EGC assumed the 8.25% Senior Notes in EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011(the “2011 Indenture”).  The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018.  On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee (the “8.25% Senior Notes Trustee”), governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of consents from the requisite holders of the 8.25% Senior  Notes in accordance with the terms and conditions of the Consent Solicitation Statement dated April 7, 2014, pursuant to which we had solicited consents (the “Consent Solicitation”) from the holders of the 8.25% Senior Notes to make certain proposed amendments to certain definitions set forth in the Indenture (the “Proposed COC Amendments”), as reflected in the Supplemental Indenture. The Consent Solicitation was made as permitted by the Merger Agreement. On April 18, 2014, we had received valid consents from holders of an aggregate principal amount of $484.1 million of the 8.25% Senior Notes and that those consents had not been revoked prior to the Consent Time. As a result, the requisite holders of the 8.25% Senior Notes had consented to the Proposed COC Amendments, upon the terms and subject to the conditions set forth in the Consent Solicitation Statement. Accordingly, EPL, the guarantors party thereto and the Trustee entered into the Supplemental Indenture. Subject to the terms and conditions set forth in the Statement, we paid an aggregate cash payment equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents to the Proposed COC Amendments were validly delivered and unrevoked.

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

6.875% Senior Notes Due 2024

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

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

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

    EGC believes that the fair value of the $650 million of 6.875% Senior Notes outstanding as of June 30, 2014 was $663 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 6.875% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

3.0% Senior Convertible Notes due 2018

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

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

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

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

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

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

7.5% Senior Notes Due 2021

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

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

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

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

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

9.25% Senior Notes

On December 17, 2010, EGC issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). It exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act of 1933, as amended (the “Securities Act”), on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from any equity raised. EGC incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.

EGC believes that the fair value of the $750 million of 9.25% Senior Notes outstanding as of June 30, 2014 was $806.6 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 9.25%  Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

7.75% Senior Notes

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

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised. EGC incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.

EGC believes that the fair value of the $250 million of 7.75% Senior Notes outstanding as of June 30, 2014 was $269.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 7.75% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

Guarantee of Securities Issued by EGC

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

4.14% Promissory Note

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

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase from our hedge counterparties. Substantially all of our hedges are with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of June 30, 2014 and June 30, 2013, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $21 million and $24.7 million, respectively.

Interest Expense

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

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

Parent Company [Member]

Long-Term Debt

Note 3 – Long-Term Debt

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

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

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Notes Payable

12 Months Ended

Jun. 30, 2014

Notes Payable [Abstract]

Notes Payable

Note 7 – Notes Payable

In May 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $26.0 million and bore interest at an annual rate of 1.556%. The note matured and was repaid on December 26, 2012.

In July 2012, we entered into a note to finance a portion of our insurance premiums. The note was for a total face amount of $3.6 million and bore interest at an annual rate of 1.667%. The note matured and was repaid on May 1, 2013. 

In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums.  The note was for a total face amount of $0.6 million and bore interest at an annual rate of 1.774%.  The note matured and was repaid on October 23, 2013. 

In May 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $24.8 million and bore interest at an annual rate of 1.623%. The note matured and was repaid on April 26, 2014. 

On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015.  The balance outstanding as of June 30, 2014 was $22.0 million.

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Derivative Financial Instruments

12 Months Ended

Jun. 30, 2014

Derivative Financial Instruments [Abstract]

Derivative Financial Instruments

Note 9 – Derivative Financial Instruments

We enter into hedging transactions with a diversified group of investment-grade rated counterparties, primarily financial institutions, for our derivative transactions to reduce the concentration of exposure to any individual counterparty and to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. The Company designates a majority of its derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled.

When the Company discontinues cash flow hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, changes to fair value accumulated in other comprehensive income are recognized immediately into earnings.

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

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. During the quarter ended September 30, 2011, the Company began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By including Brent benchmarks in our crude hedging, we can more appropriately manage our exposure and price risk. In April 2014 we began including Argus-LLS futures collars in our hedging portfolio to appropriately align and manage our exposure and price risk to market conditions.

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

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

We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended June 30, 2013, and received $181.3 million.  These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts.  As of June 30, 2014, all of the monetized amounts remaining in OCI were recognized in income.

During the year ended June 30, 2013, we repositioned certain hedge positions by selling puts on certain existing calendar year 2013 hedge collar contracts and purchasing new put spread contracts. The $2.2 million received from the sale of puts were recorded as deferred hedge revenue and were recognized in income over the life of the underlying hedge contracts through December 31, 2013.  As of June 30, 2014, all of the amounts remaining in deferred hedge revenue were recognized in income.

As of June 30, 2014, we had the following net open crude oil derivative positions:

					Weighted Average Contract Price
					Swaps		Collars/Put Spreads
			Volumes			Sub
Period	Type of Contract	Index	(MBbls)	Fixed Price		Floor		Floor		Ceiling
July 2014 - December 2014	Three-Way Collars	Oil-Brent-IPE	766			$	69.00	$	89.00	$	124.99
July 2014 - December 2014	Put Spreads	Oil-Brent-IPE	431				66.43		86.43
July 2014 - December 2014	Collars	Oil-Brent-IPE	368						90.00		108.38
July 2014 - December 2014	Put Spreads	NYMEX-WTI	1,230				70.00		90.00
July 2014 - December 2014	Put	NYMEX-WTI	460						90.00
July 2014 - December 2014	Roll Swap	NYMEX-WTI	2,295	$	1.03
July 2014 - December 2014	Three-Way Collars	NYMEX-WTI	610				70.00		90.00		137.20
July 2014 - December 2014	Swaps	ARGUS-LLS	1,614		92.84
January 2015 - December 2015	Three-Way Collars	Oil-Brent-IPE	3,650				71.00		91.00		113.75
January 2015 - December 2015	Swaps	Oil-Brent-IPE	548		97.70
January 2015 - December 2015	Collars	ARGUS-LLS	1,825						80.00		123.38
January 2015 - December 2015	Put	NYMEX-WTI	1,813						88.76
January 2015 - December 2015	Roll Swap	NYMEX-WTI	3,180		1.03

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

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

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

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

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

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

The cash flow hedging relationship of our derivative instruments was as follows (in thousands):

		Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss,		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss,		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss
		net of tax		net of tax		(Ineffective
Location of (Gain) Loss		(Effective Portion)		(Effective Portion)		Portion)
Year Ended June 30, 2014
Commodity Derivative Instruments	$	47,027
Revenues			$	(6,640)
Loss (gain) on derivative financial instruments					$	6,339
Total	$	47,027	$	(6,640)	$	6,339
Year Ended June 30, 2013
Commodity Derivative Instruments	$	31,051
Revenues			$	(25,876)
Loss (gain) on derivative financial instruments					$	881
Total	$	31,051	$	(25,876)	$	881
Year Ended June 30, 2012
Commodity Derivative Instruments	$	(126,087)
Revenues			$	(22,372)
Loss (gain) on derivative financial instruments					$	(3,479)
Total	$	(126,087)	$	(22,372)	$	(3,479)

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

	Before Tax		After Tax		Location Where Consolidated Net Income is Presented
Year ended June 30, 2014
Unrealized gain on derivatives at beginning of the year	$	(40,851)	$	(26,552)
Unrealized change in fair value during the year		55,794		36,266
Ineffective portion reclassified to earnings during the year		6,339		4,121	Loss on derivative financial instruments
Realized amounts reclassified to earnings during the year		10,215		6,640	Revenues
Unrealized loss on derivatives at the end of the year		31,497		20,475
	Before Tax		After Tax		Location Where Consolidated Net Income is Presented
Year ended June 30, 2013
Unrealized gain on derivatives at beginning of the year	$	(88,620)	$	(57,603)
Unrealized change in fair value during the year		7,078		4,601
Ineffective portion reclassified to earnings during the year		881		573	Loss on derivative financial instruments
Realized amounts reclassified to earnings during the year		39,810		25,887	Revenues
Unrealized gain on derivatives at the end of the year		(40,851)		(26,552)
	Before Tax		After Tax		Location Where Consolidated Net Income is Presented
Year ended June 30, 2012
Unrealized loss on derivatives at beginning of the year	$	105,360	$	68,484
Unrealized change in Fair value during the year		(224,919)		(146,197)
Ineffective portion reclassified to earnings during the year		(3,479)		(2,261)	Loss on derivative financial instruments
Realized amounts reclassified to earnings during the year		34,418		22,371	Revenues
Unrealized gain on derivatives at end of the year	$	(88,620)	$	(57,603)

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $24.9 million ($16.2 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At June 30, 2014, we had no deposits for collateral with our counterparties.

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Long-Term Debt (Interest Expense) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended			0 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	Dec. 17, 2010	Jun. 03, 2014	Feb. 25, 2011	Sep. 26, 2013	May 27, 2014	Nov. 18, 2013
Debt Instrument [Line Items]
Interest expense	$ 162,728	$ 108,659	$ 108,882
Amortization of debt issue cost	(33,461)	(4,805)
Debt instrument, stated interest rate	6.875%	6.875%
Parent Company [Member]
Debt Instrument [Line Items]
Interest expense	14,485	5
Amortization of debt issue cost	(9,585)
9.25% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Interest expense	69,375	69,375	69,375
Debt instrument, stated interest rate		9.25%		9.25%
Debt maturity date				Dec. 15, 2017
9.25% Senior Notes Due 2017 [Member] | Amortization of Debt Issue Cost [Member]
Debt Instrument [Line Items]
Amortization of debt issue cost	2,206	2,206	2,206
8.25% Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Interest expense	3,507
Debt instrument, stated interest rate					8.25%
Debt maturity date					Feb. 15, 2018
8.25% Senior Notes Due 2018 [Member] | Premium Amortization [Member]
Debt Instrument [Line Items]
Amortization of debt issue cost	(841)
7.75% Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Interest expense	19,375	19,375	19,375
Debt instrument, stated interest rate		7.75%				7.75%
Debt maturity date						Jun. 15, 2019
7.75% Senior Notes Due 2019 [Member] | Amortization of Debt Issue Cost [Member]
Debt Instrument [Line Items]
Amortization of debt issue cost	388	388	388
7.50% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Interest expense	28,542
Debt instrument, stated interest rate							7.50%
Debt maturity date							Dec. 15, 2021
7.50% Senior Notes Due 2021 [Member] | Amortization of Debt Issue Cost [Member]
Debt Instrument [Line Items]
Amortization of debt issue cost	783
6.875% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Interest expense	4,096
Debt instrument, stated interest rate								6.875%
Debt maturity date								Mar. 15, 2024
6.875% Senior Notes Due 2024 [Member] | Amortization of Debt Issue Cost [Member]
Debt Instrument [Line Items]
Amortization of debt issue cost	102
3.0% Senior Convertible Notes due 2018 [Member]
Debt Instrument [Line Items]
Interest expense	7,266
Debt instrument, stated interest rate									3.00%
Debt maturity date									Dec. 31, 2018
3.0% Senior Convertible Notes due 2018 [Member] | Discount Amortization [Member]
Debt Instrument [Line Items]
Amortization of original issue discount	6,418
3.0% Senior Convertible Notes due 2018 [Member] | Premium Amortization [Member]
Debt Instrument [Line Items]
Amortization of debt issue cost	801
4.14% Promissory Note Due 2017 [Member]
Debt Instrument [Line Items]
Interest expense	210
Debt instrument, stated interest rate	4.14%
Derivative Instruments Premium Financing [Member]
Debt Instrument [Line Items]
Interest expense	987	1,196	1,347
Bridge Commitment Fee [Member]
Debt Instrument [Line Items]
Interest expense	2,481
Settlement of Lehman Brothers Liability [Member]
Debt Instrument [Line Items]
Interest expense			1,890
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Interest expense	13,956	11,816	9,420
Revolving Credit Facility [Member] | Amortization of Debt Issue Cost [Member]
Debt Instrument [Line Items]
Amortization of debt issue cost	$ 3,076	$ 4,303	$ 4,881

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Income Taxes (Income Before Income Tax) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Income Taxes [Abstract]
U.S. income	$ 106,970	$ 223,337	$ 346,887
Non-U.S. income	9,230	25,377	27,586
Income Before Income Taxes	$ 116,200	$ 248,714	$ 374,473

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Asset Retirement Obligations (Changes in Asset Retirement Obligations) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Asset Retirement Obligations [Abstract]
Balance at beginning of year	$ 287,818	$ 301,415
Liabilities acquired	284,661	7,277
Liabilities incurred and true up of liabilities settled	41,216	18,486
Liabilities settled	(57,391)	(41,939)
Revisions in estimated cash flows	(26,653)	(28,306)
Accretion expense	30,183	30,885
Total balance at end of year	559,834	287,818
Less current portion	79,649	29,500
Long-term balance at end of year	$ 480,185	$ 258,318

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Supplemental Guarantor Information (Condensed Consolidating Balance Sheet) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2011
Current Assets
Cash and cash equivalents	$ 145,806		$ 117,087	$ 28,407
Accounts receivable
Oil and natural gas sales	167,075	132,521
Joint interest billings	12,898	9,505
Insurance and other	5,438	6,745
Prepaid expenses and other current assets	72,530	50,738
Deferred income taxes	52,587
Derivative financial instruments	1,425	38,389
Total Current Assets	457,759	237,898
Property and Equipment
Oil and natural gas properties	6,524,602	3,289,505
Other property and equipment	19,760	17,003
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	6,544,362	3,306,508
Other Assets
Goodwill	327,235
Derivative financial instruments	3,035	21,926
Equity investments	40,643	12,799
Intercompany receivables
Restricted cash	6,350
Deferred income taxes
Other assets and debt issuance costs, net	57,394	32,580
Total Other Assets	434,657	67,305
Total Assets	7,436,778	3,611,711
Current Liabilities
Accounts payable	415,718	219,610
Accrued liabilities	133,526	105,192
Notes payable	21,967	22,524
Deferred income taxes		20,517
Asset retirement obligations	79,649	29,500
Derivative financial instruments	31,957	40
Current maturities of long-term debt	15,020	19,554
Total Current Liabilities	697,837	416,937
Long-term debt, less current maturities	3,744,624	1,350,491
Deferred income taxes	701,038	140,804
Asset retirement obligations	480,185	258,318
Derivative financial instruments	4,306
Intercompany payables
Other liabilities	10,958	7,915
Total Liabilities	5,638,948	2,174,465
Stockholders' Equity
Common Stock	468	397
Additional paid-in capital	1,837,462	1,512,311
Retained earnings (accumulated deficit)	(19,626)	(29,352)
Accumulated other comprehensive (loss) income, net of income taxes	(20,475)	26,552
Treasury stock	(170,266)	(72,663)
Total Stockholders' Equity	1,797,830	1,437,246	1,405,840	946,697
Total Liabilities and Stockholders' Equity	7,436,778	3,611,711
Reclassifications & Eliminations [Member]
Current Assets
Cash and cash equivalents		(1,471)
Accounts receivable
Oil and natural gas sales	(11,688)	(17,486)
Insurance and other	(1)
Prepaid expenses and other current assets		1
Total Current Assets	(11,689)	(18,956)
Property and Equipment
Oil and natural gas properties	1,914
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	1,914
Other Assets
Equity investments	(6,783,943)	(3,858,002)
Intercompany receivables	(1,790,982)	(2,056,997)
Deferred income taxes		(29,884)
Other assets and debt issuance costs, net	(171,000)	(171,000)
Total Other Assets	(8,745,925)	(6,115,883)
Total Assets	(8,755,700)	(6,134,839)
Current Liabilities
Accounts payable	(11,881)	(18,956)
Accrued liabilities	(63,952)	(56,279)
Deferred income taxes	(19,185)
Total Current Liabilities	(95,018)	(75,235)
Long-term debt, less current maturities	(171,000)	(171,000)
Deferred income taxes	19,185	(29,884)
Intercompany payables	(1,736,240)	(1,913,195)
Total Liabilities	(1,983,073)	(2,189,314)
Stockholders' Equity
Common Stock	(11)
Additional paid-in capital	(5,945,572)	(3,166,193)
Retained earnings (accumulated deficit)	(874,206)	(726,483)
Accumulated other comprehensive (loss) income, net of income taxes	47,162	(52,849)
Total Stockholders' Equity	(6,772,627)	(3,945,525)
Total Liabilities and Stockholders' Equity	(8,755,700)	(6,134,839)
Parent Company [Member]
Current Assets
Cash and cash equivalents	135,703	1,334	9,830	28,689
Accounts receivable
Insurance and other	10
Prepaid expenses and other current assets	230	235
Total Current Assets	135,943	1,569
Other Assets
Equity investments	1,744,908	1,259,247
Intercompany receivables	102,489	95,627
Other assets and debt issuance costs, net	178,299	171,000
Total Other Assets	2,025,696	1,525,874
Total Assets	2,161,639	1,527,443
Current Liabilities
Accrued liabilities	1,640	479
Notes payable		175
Deferred income taxes	19,185
Total Current Liabilities	20,825	654
Long-term debt, less current maturities	342,986
Deferred income taxes		16,883
Total Liabilities	363,811	17,537
Stockholders' Equity
Common Stock	468	396
Additional paid-in capital	1,837,462	1,512,310
Retained earnings (accumulated deficit)	(19,628)	(29,352)
Accumulated other comprehensive (loss) income, net of income taxes	(20,475)	26,551
Total Stockholders' Equity	1,797,828	1,509,906
Total Liabilities and Stockholders' Equity	2,161,639	1,527,443
Energy XXI Gulf Coast Inc [Member]
Current Assets
Cash and cash equivalents	3,723		45,394	(656)
Accounts receivable
Joint interest billings	1,833	9,505
Insurance and other	3,452	6,031
Prepaid expenses and other current assets	27,705	47,492
Deferred income taxes	27,424
Derivative financial instruments	1,425	38,389
Total Current Assets	65,562	101,417
Property and Equipment
Oil and natural gas properties		16,553
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		16,553
Other Assets
Derivative financial instruments	3,035	21,926
Equity investments	2,969,070	1,066,803
Intercompany receivables	1,627,931	1,904,655
Other assets and debt issuance costs, net	42,155	24,791
Total Other Assets	4,642,191	3,018,175
Total Assets	4,707,753	3,136,145
Current Liabilities
Accounts payable	64,533	104,263
Accrued liabilities	12,501	25,001
Notes payable	21,967	22,349
Derivative financial instruments	5,517	40
Current maturities of long-term debt	14,093	18,838
Total Current Liabilities	118,611	170,491
Long-term debt, less current maturities	2,305,906	1,279,843
Deferred income taxes	211,055	153,805
Asset retirement obligations	49	50
Derivative financial instruments	2,166
Total Liabilities	2,637,787	1,604,189
Stockholders' Equity
Common Stock	1	1
Additional paid-in capital	2,092,439	1,426,351
Retained earnings (accumulated deficit)	(2,040)	79,304
Accumulated other comprehensive (loss) income, net of income taxes	(20,434)	26,300
Total Stockholders' Equity	2,069,966	1,531,956
Total Liabilities and Stockholders' Equity	4,707,753	3,136,145
Guarantor Subsidiaries [Member]
Accounts receivable
Oil and natural gas sales	127,773	150,007
Insurance and other	517	495
Prepaid expenses and other current assets	350	372
Total Current Assets	128,640	150,874
Property and Equipment
Oil and natural gas properties	3,324,923	3,272,952
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	3,324,923	3,272,952
Other Assets
Restricted cash	325
Total Other Assets	325
Total Assets	3,453,888	3,423,826
Current Liabilities
Accounts payable	150,909	133,045
Accrued liabilities	28,750	30,393
Asset retirement obligations	39,819	29,500
Total Current Liabilities	219,478	192,938
Asset retirement obligations	247,272	258,268
Intercompany payables	1,736,240	1,913,195
Total Liabilities	2,202,990	2,364,401
Stockholders' Equity
Additional paid-in capital	273,129	369,195
Retained earnings (accumulated deficit)	977,769	690,231
Accumulated other comprehensive (loss) income, net of income taxes		(1)
Total Stockholders' Equity	1,250,898	1,059,425
Total Liabilities and Stockholders' Equity	3,453,888	3,423,826
Non-Guarantor Subsidiaries [Member]
Current Assets
Cash and cash equivalents	6,380	137	61,863	374
Accounts receivable
Oil and natural gas sales	50,990
Joint interest billings	11,065
Insurance and other	1,460	219
Prepaid expenses and other current assets	44,245	2,638
Deferred income taxes	25,163
Total Current Assets	139,303	2,994
Property and Equipment
Oil and natural gas properties	3,197,765
Other property and equipment	19,760	17,003
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	3,217,525	17,003
Other Assets
Goodwill	327,235
Equity investments	2,110,608	1,544,751
Intercompany receivables	60,562	56,715
Restricted cash	6,025
Deferred income taxes		29,884
Other assets and debt issuance costs, net	7,940	7,789
Total Other Assets	2,512,370	1,639,139
Total Assets	5,869,198	1,659,136
Current Liabilities
Accounts payable	212,157	1,258
Accrued liabilities	154,587	105,598
Deferred income taxes		20,517
Asset retirement obligations	39,830
Derivative financial instruments	26,440
Current maturities of long-term debt	927	716
Total Current Liabilities	433,941	128,089
Long-term debt, less current maturities	1,266,732	241,648
Deferred income taxes	470,798
Asset retirement obligations	232,864
Derivative financial instruments	2,140
Other liabilities	10,958	7,915
Total Liabilities	2,417,433	377,652
Stockholders' Equity
Common Stock	10
Additional paid-in capital	3,580,004	1,370,648
Retained earnings (accumulated deficit)	(101,521)	(43,052)
Accumulated other comprehensive (loss) income, net of income taxes	(26,728)	26,551
Treasury stock		(72,663)
Total Stockholders' Equity	3,451,765	1,281,484
Total Liabilities and Stockholders' Equity	5,869,198	1,659,136
7.25% Convertible Perpetual Preferred Stock [Member]
Stockholders' Equity
Preferred stock
5.625% Convertible Perpetual Preferred Stock [Member]
Stockholders' Equity
Preferred stock	1	1
5.625% Convertible Perpetual Preferred Stock [Member] | Parent Company [Member]
Stockholders' Equity
Preferred stock	$ 1	$ 1

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Long-Term Debt (Maturities of Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Long-Term Debt [Abstract]
2015	$ 15,020
2016	7,844
2017	751
2018	1,993,043
2019	592,986
Thereafter	1,150,000
Total debt	$ 3,759,644	$ 1,370,045

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Prepayments and Accrued Liabilities (Components of Prepayments and Accrued Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Prepaid expenses and other current assets
Advances to joint interest partners	$ 10,336	$ 13,936
Insurance	37,088	31,258
Inventory	7,020	4,094
Royalty deposit	12,262	1,210
Other	5,824	240
Total prepaid expenses and other current assets	72,530	50,738
Accrued liabilities
Advances from joint interest partners	2,667	1,348
Employee benefits and payroll	43,480	30,730
Interest payable	26,490	5,733
Accrued hedge payable	7,874	2,214
Undistributed oil and gas proceeds	34,473	47,766
Severance taxes payable	8,014	922
Repurchase of company common stock		13,997
Other	10,528	2,482
Total accrued liabilities	133,526	105,192
Parent Company [Member]
Prepaid expenses and other current assets
Total prepaid expenses and other current assets	230	235
Accrued liabilities
Total accrued liabilities	$ 1,640	$ 479

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Acquisitions and Dispositions (Tables)

12 Months Ended

Jun. 30, 2014

Restructuring Cost and Reserve [Line Items]

Summary of Business Acquisition

Following is a summary of the total purchase price of approximately $1,504.3 million, including cash acquired of $206.1 million (in millions other than per share amounts):

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

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

Summary of Pro Forma Financial Information

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

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

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

Gulf of Mexico Interests [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation to the Assets Acquired and Liabilities Assumed

The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on October 17, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	10,447
Oil and natural gas properties – unevaluated		27,721
Asset retirement obligations		(5,351)
Cash paid	$	32,817

Dynamic Interests [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation to the Assets Acquired and Liabilities Assumed

The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	1,753
Oil and natural gas properties – unevaluated		6,571
Asset retirement obligations		(1,091)
Cash paid	$	7,233

McMoran Interest [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation to the Assets Acquired and Liabilities Assumed

The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	62,499
Oil and natural gas properties – unevaluated		17,184
Asset retirement obligations		(382)
Cash paid	$	79,301

Roda Interest [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation to the Assets Acquired and Liabilities Assumed

The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 14, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	32,777
Asset retirement obligations		(115)
Cash paid	$	32,662

Tammany Oil and Gas Properties [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation to the Assets Acquired and Liabilities Assumed

The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on June 28, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	8,626
Asset retirement obligations		(338)
Cash paid	$	8,288

Black Elk Interest [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation to the Assets Acquired and Liabilities Assumed

The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 (in thousands):

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

*  Net working capital includes payables.

Walter Oil & Gas Corporation [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation to the Assets Acquired and Liabilities Assumed

The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):

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

EPL Oil & Gas, Inc. [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation to the Assets Acquired and Liabilities Assumed

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

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

a.EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.

b.Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37 percent tax rate, which reflected the 35 percent federal statutory rate and a 2 percent weighted-average of the applicable statutory state tax rates (net of federal benefit).

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

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Acquisitions and Dispositions (EPL Acquisition) (Narrative) (Details) (USD $)	0 Months Ended		3 Months Ended								12 Months Ended			1 Months Ended
	Jun. 03, 2014		Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2014	Jun. 03, 2013
Restructuring Cost and Reserve [Line Items]
Shares issued upon the closing of EPL acquisition	23,320,955
Operating income			$ 54,677,000	$ 64,801,000	$ 61,502,000	$ 99,431,000	$ 111,747,000	$ 99,870,000	$ 93,537,000	$ 56,651,000	$ 280,411,000	$ 361,805,000	$ 483,284,000
Net income			(1,815,000)	7,292,000	10,495,000	43,139,000	62,053,000	40,436,000	41,332,000	18,260,000	59,111,000	162,081,000	335,827,000
EPL Oil & Gas, Inc. [Member]
Restructuring Cost and Reserve [Line Items]
Date of acquisition	Jun. 03, 2014
Business acquisition, per share price of acquiree's share															$ 39.00
Percentage of aggregate consideration paid in cash	65.00%
Percentage of aggregate consideration paid in common shares	35.00%
Cash value of purchase price	1,012,000,000
Shares issued upon the closing of EPL acquisition	23,320,955
Total cash value of purchase price	1,504,300,000
Acquisition related costs, included in selling, general and administrative expenses														13,600,000
Cash acquired in acquisition	(206,075,000)
Operating income														60,100,000
Net income												57,600,000		4,200,000
EPL Oil & Gas, Inc. [Member] | Cash Election [Member]
Restructuring Cost and Reserve [Line Items]
Share conversion ratio	0.5595
Business Acquisition, per share price of acquiror share	25.92
Cash value of purchase price	792,600,000
Shares issued upon the closing of EPL acquisition	17,108,300
Total cash value of purchase price	1,153,800,000
EPL Oil & Gas, Inc. [Member] | Mixed Election [Member]
Restructuring Cost and Reserve [Line Items]
Share conversion ratio	0.584	[1]
Business Acquisition, per share price of acquiror share	25.35	[1]
Cash value of purchase price	186,800,000	[1]
Shares issued upon the closing of EPL acquisition	4,303,700	[1]
Total cash value of purchase price	277,600,000	[1]
EPL Oil & Gas, Inc. [Member] | Stock Election [Member]
Restructuring Cost and Reserve [Line Items]
Share conversion ratio	1.669
Shares issued upon the closing of EPL acquisition	1,909,000
Total cash value of purchase price	40,300,000
EPL Oil & Gas, Inc. [Member] | Stock Option [Member]
Restructuring Cost and Reserve [Line Items]
Business acquisition, per share price of acquiree's share	39.00
Cash value of purchase price	32,600,000
EPL stock options converted	836,311
Total cash value of purchase price	32,600,000

[1] Includes 4.7 million EPL shares, held by EPL stockholders and did not make an election prior to the May 30, 2014 election deadline.

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Earnings per Share

12 Months Ended

Jun. 30, 2014

Earnings per Share [Abstract]

Earnings per Share

Note 14 — Earnings per Share

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

		Year Ended June 30,
		2014		2013		2012
Net income	$	59,111	$	162,081	$	335,827
Preferred stock dividends		11,489		11,496		13,028
Induced conversion of preferred stock		—				6,068
Net income available for common stockholders	$	47,622	$	150,585	$	316,731
Weighted average shares outstanding for basic EPS		74,375		79,063		77,310
Add dilutive securities		70		8,200		9,898
Weighted average shares outstanding for diluted EPS		74,445		87,263		87,208
Earnings per share
Basic	$	0.64	$	1.90	$	4.10
Diluted	$	0.64	$	1.86	$	3.85

For the years ended June 30, 2014, 2013 and 2012, we had 8,336,700,  5,474 and 4,821, respectively, of common stock equivalents that were excluded from the diluted average shares due to an anti-dilutive effect.

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Prepayments and Accrued Liabilities

12 Months Ended

Jun. 30, 2014

Prepayments and Accrued Liabilities [Abstract]

Prepayments and Accrued Liabilities

Note 19 — Prepayments and Accrued Liabilities

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

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

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Supplementary Oil and Gas Information (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014 MBoe	Jun. 30, 2013 MBoe	Jun. 30, 2012 MBoe	Jun. 30, 2011 MBoe
Reserve Quantities [Line Items]
Proved undeveloped reserves	96,256.0	69,007.0	37,931.0	35,020.0
Proved developed reserves, MBOE	149,942.0	109,493.0	81,693.0	81,572.0
Cost associated with acquisition of proved reserves	$ 2,046,879	$ 108,825	$ 6,401
Extensions and discoveries	20,424.0	47,476.0	16,081.0
Development costs	632,262	633,868	327,360
Oil Reserves [Member]
Reserve Quantities [Line Items]
Average adjusted product prices	103.80
Oil Reserves [Member] | West Texas Intermediate [Member]
Reserve Quantities [Line Items]
Commodity prices used in determining future cash flows before differentials	96.75
Unweighted average price for first-day-of-the-month	96.75
Differential price	7.05
Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Average price of Natural Gas Liquids	42.10
Average adjusted Natural Gas price	4.14
Natural Gas Reserves [Member] | Henry Hub [Member]
Reserve Quantities [Line Items]
Commodity prices used in determining future cash flows before differentials	4.10
Proved Developed Reserves [Member]
Reserve Quantities [Line Items]
Proved developed reserves, MBOE	149.9	109.5
Increase percentage of additions to proved developed reserves from 4 fields	37.00%
Increase (decrease) in proved reserve estimates	40.4
Extensions and discoveries	5.4
Proved Developed Reserves [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Increase percentage of additions to proved developed reserves from 4 fields	80.00%
Proved Developed Reserves downward revision	2.7
Production	16.4
Divestiture	4.7
Wells developed, gross	18
Wells developed, net	18
Development costs	160,900
Proved undeveloped reserves reclassified to proved developed, percentage	9.50%
Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves	96.3	69.0
Increase percentage of additions to proved developed reserves from four fields	40.00%
Increase (decrease) in proved reserve estimates	27.3
Development costs	$ 101,700
Proved Undeveloped Reserves [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Number of PUDs not scheduled for conversion within requirement period	2
Increase (decrease) in proved reserve estimates	15.1
Proved Developed Reserves downward revision	5.9
Proved Undeveloped Converted To Developed [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves changed to proved developed reserves	6.6
EPL Oil & Gas, Inc. [Member] | Proved Developed Reserves [Member]
Reserve Quantities [Line Items]
Proved developed, acquisitions	52.3
EPL Oil & Gas, Inc. [Member] | Proved Undeveloped Reserves [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Proved undeveloped, acquisitions	24.6

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Organization and Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2009
Organization And Significant Accounting Policies [Line Items]
Allowance for doubtful accounts receivable	$ 0	$ 0
Capitalized general and administrative expense	64,500,000	37,600,000	38,300,000
U.S. withholding tax rate on any interest payments	30.00%
Valuation allowance	22,494,000	22,494,000		175,000,000
Common stock, par value	$ 0.005	$ 0.005
Parent Company [Member]
Organization And Significant Accounting Policies [Line Items]
Amount of restricted net assets	$ 1,380,000,000
Maximum [Member]
Organization And Significant Accounting Policies [Line Items]
Liquid investments maturity period	90 days
Maximum [Member] | Other Property [Member]
Organization And Significant Accounting Policies [Line Items]
Useful life of properties	5 years
Minimum [Member] | Other Property [Member]
Organization And Significant Accounting Policies [Line Items]
Useful life of properties	3 years

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Notes Receivable (Narrative) (Details) (Parent Company [Member], USD $)	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Parent Company [Member]
Promissory notes to a wholly owned subsidiary	$ 171,000,000	$ 171,000,000
Promissory note, interest rate	9.75%
Interest income	$ 16,700,000	$ 16,700,000	$ 16,700,000

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Earnings per Share (Tables)

12 Months Ended

Jun. 30, 2014

Earnings per Share [Abstract]

Calculation of Basic and Diluted Earnings per Share

The following table sets forth the calculation of basic and diluted earnings per share (“EPS”) (in thousands, except per share data):

		Year Ended June 30,
		2014		2013		2012
Net income	$	59,111	$	162,081	$	335,827
Preferred stock dividends		11,489		11,496		13,028
Induced conversion of preferred stock		—				6,068
Net income available for common stockholders	$	47,622	$	150,585	$	316,731
Weighted average shares outstanding for basic EPS		74,375		79,063		77,310
Add dilutive securities		70		8,200		9,898
Weighted average shares outstanding for diluted EPS		74,445		87,263		87,208
Earnings per share
Basic	$	0.64	$	1.90	$	4.10
Diluted	$	0.64	$	1.86	$	3.85

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

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Income Taxes (Components of Deferred Taxes) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2009
Income Taxes [Abstract]
Deferred tax liabilities, federal withholding obligation		$ (20,517)
Deferred tax assets - current
Asset retirement obligation	44,182
Other	8,405
Total deferred tax assets - current	52,587
Deferred tax assets - non current
Asset retirement obligation	61,412	100,697
Tax loss carryforwards on U.S. operations	448,404	386,899
Accrued interest expense	79,636	65,418
Deferred interest expense under IRC Sec. 162(j)		28,721
Employee benefit plans		6,213
Deferred state taxes	22,494	22,494
Derivative instruments and other	12,163
Other	11,471	6,860
Total deferred tax assets - non current	635,580	617,302
Deferred tax liabilities
Derivative instruments and other		(10,193)
Oil, natural gas properties and other property and equipment	(1,183,864)	(628,554)
Federal withholding obligation	(63,143)	(34,983)
Cancellation of debt	(9,680)	(9,680)
Employee benefit plans	(3,611)
Tax partnership activity	(53,826)	(52,202)
Total deferred tax liabilities - non current	(1,314,124)	(735,612)
Valuation allowance	(22,494)	(22,494)	(175,000)
Net deferred tax asset (liability)	(648,451)	(161,321)
Reflected in the accompanying balance sheet as Current deferred tax asset (liability)	52,587	(20,517)
Reflected in the accompanying balance sheet as Non-current deferred tax asset (liability)	$ (701,038)	$ (140,804)

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Acquisitions and Dispositions

12 Months Ended

Jun. 30, 2014

Acquisitions and Dispositions [Abstract]

Acquisitions and Dispositions

Note 3 – Acquisitions and Dispositions

ExxonMobil oil and gas properties interests acquisition

    On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“ExxonMobil”) for a total cash consideration of approximately $32.8 million.  The GOM Interests cover 5,000 gross acres on Vermilion Block 164(“VR 164”).  We are the operator of these properties.  In addition to acquiring the GOM Interests, we entered into a joint venture agreement with ExxonMobil to explore for oil and gas on nine contiguous blocks adjacent to VR 164 in shallow waters on the GOM shelf.  We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012. The objective targets at Pendragon well, the initial prospect, were not reached as it encountered mechanical issues and was plugged and abandoned.  Subsequently, we began drilling the Merlin well located at Vermilion Block 179; the Merlin well did not encounter any commercial hydrocarbons and was plugged and abandoned. We are currently negotiating an extension of our joint venture with ExxonMobil to further analyze the Pendragon and Merlin wells’ data along with reprocessing the 3D seismic information to determine the future drilling activities on the Vermilion Block. 

    Revenues and expenses related to the GOM Interests from the closing date of October 17, 2012 are included in our consolidated statements of income.  The acquisition of the GOM Interests was accounted for under the purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on October 17, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	10,447
Oil and natural gas properties – unevaluated		27,721
Asset retirement obligations		(5,351)
Cash paid	$	32,817

Dynamic Offshore oil and gas properties interests acquisition

    On November 7, 2012, we acquired 100% of the interests (“Dynamic Interests”) held by Dynamic Offshore Resources, LLC (“Dynamic”) on VR 164 for approximately $7.2 million. 

    Revenues and expenses related to the Dynamic Interests from the closing date of November 7, 2012 are included in our consolidated statements of income.  The acquisition of the Dynamic Interests was accounted for under the purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	1,753
Oil and natural gas properties – unevaluated		6,571
Asset retirement obligations		(1,091)
Cash paid	$	7,233

McMoRan oil and gas properties interests acquisition

    On January 17, 2013, we closed on the acquisition of certain onshore Louisiana interests in the Bayou Carlin  field (“Bayou Carlin  Interests”) from McMoRan Oil and Gas, LLC (“McMoRan”) for a total cash consideration of $79.3 million.  This acquisition was effective as of January 1, 2013.  We are the operator of these properties. 

    Revenues and expenses related to the Bayou Carlin Interests from the closing date of January 17, 2013 are included in our consolidated statements of income.  The acquisition of the Bayou Carlin Interests was accounted for under purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	62,499
Oil and natural gas properties – unevaluated		17,184
Asset retirement obligations		(382)
Cash paid	$	79,301

RoDa oil and gas properties interests acquisition

    On March 14, 2013, we acquired 100% of the interests (“RoDa Interests”) held by RoDa Drilling LP (“RoDa”) in the Bayou Carlin  field for $32.7 million. This acquisition was effective as of January 1, 2013.

    Revenues and expenses related to the RoDa Interests from the closing date of March 14, 2013 are included in our consolidated statements of income.  The acquisition of the RoDa Interests was accounted for under the purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 14, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	32,777
Asset retirement obligations		(115)
Cash paid	$	32,662

Tammany oil and gas properties interests acquisition

On June 28, 2013, we closed on the acquisition of certain offshore Louisiana interests in the West Delta field (“West Delta Interests”) from Tammany Energy Ventures, LLC (“Tammany”) for a total cash consideration of $8.3 million.  This acquisition was effective as of June 1, 2013.  We are the operator of these properties. 

Revenues and expenses related to the West Delta Interests are included in our consolidated statements of income from July 1, 2013.  The acquisition of West Delta Interests was accounted for under the purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on June 28, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	8,626
Asset retirement obligations		(338)
Cash paid	$	8,288

Black Elk Interest

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

    Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of income from December 20, 2013.  The acquisition of West Delta 30 Interests was accounted for under purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 (in thousands):

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

*  Net working capital includes payables.

Walter Oil & Gas Corporation oil and gas properties interests acquisition

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

    Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of income from March 7, 2014.  The acquisition of South Timbalier 54 Interests was accounted for under purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):

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

The fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions were measured using valuation techniques that convert future cash flows to a single discounted amount. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.  

Apache Joint Venture

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

    The area of mutual interest under this Exploration Agreement includes several salt domes within a 135 block area.  Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 millionof which approximately $33.7 million was incurred through June 30, 2014.  Drilling on the first well commenced in May 2013 on the southern flank of the salt dome, penetrating eight oil sands and one gas bearing sand.  In February 2014 we commenced drilling an offset well which also encountered multiple hydrocarbon bearing sands.  Presently both the wellbores have been suspended for future utility and we expect to complete 3D wide azimuth (“WAZ”) seismic data analysis in December 2014.  As of June 30, 2014, our share of costs related to these wells was approximately $28.1 million.

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

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

    In the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash ("Cash Election"), or 1.669 shares of Energy XXI common stock ("Stock Election") or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock ("Mixed Election" and collectively the ("Merger Consideration")), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock.  Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share.  Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election.  In addition to the outstanding EPL shares shown below, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration.  As a result, in accordance with the Merger Agreement, 836,311 net exercise shares were converted into $39.00 in cash, without proration.

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

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

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

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

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

a.EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.

b.Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37 percent tax rate, which reflected the 35 percent federal statutory rate and a 2 percent weighted-average of the applicable statutory state tax rates (net of federal benefit).

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

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

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

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

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

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

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

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

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

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

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

a. Exclude $43.3 million of EPL’s exploration costs, impairment expense and gain on sales of assets accounted for under the successful efforts method of accounting to correspond with EXXI’s full cost method of accounting.

b.     Increase DD&A expense by $64.2 million for the EPL Properties to correspond with EXXI’s full cost method of accounting.

c.Increase interest expense by $47.8 million to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under EXXI’s revolving credit facility for approximately eleven months ended June 3, 2014.  Decrease interest expense $13.7 million to reflect non-cash interest expense associated with the $510 million of EPL’s 8.25% Senior Notes due to the adjustment to fair value of the assumed EPL debt obligations.

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

a. Include net earnings of $57.6 million which represents incremental revenues, lease operating and other direct operating expenses related to EPL’s acquisitions and divestitures from July 1, 2012 to the date of such transactions.

b. Increase DD&A expense by $116.0 million for the EPL Properties to correspond with EXXI’s full cost method of accounting.

c. Increase interest expense by $51.9 million to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under EXXI’s revolving credit facility for the twelve months ending June 30, 2013.  Decrease interest expense $7.0 million to reflect non-cash interest expense associated with the $510 million of EPL’s 8.25% Senior Notes due to the adjustment to fair value of the assumed EPL debt obligations, net of interest expense of ProceedsFromDivestitureOfInterestInJointVenture$5.4 million to reflect interest on the 8.25% Senior Notes from July 1, 2012.

Sale of Oil and Natural Gas properties interests

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

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

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

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Property and Equipment (Summary of Wells in Progress and Their Status) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Jun. 30, 2014
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Costs incurred	$ 185.3
Davy Jones Facilities [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Costs incurred	22.1
Description of current status of project	Facilities cost in Davy Jones field for well operations.
Davy Jones Offset Appraisal Well [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Costs incurred	69.8
Description of current status of project	Davy Jones Offset Appraisal Well is awaiting test of Wilcox sands.
Blackbeard East [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Costs incurred	50.8
Description of current status of project	Plans to complete into the Miocene Sands in late 2015.
Lomond North [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Costs incurred	$ 42.6
Description of current status of project	Completion operations in progress to test lower Wilcox and Cretaceous objectives

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Commitments and Contingencies (Narrative) (Details) (USD $)	12 Months Ended
	Jun. 30, 2014 contract	Jun. 30, 2013	Jun. 30, 2012	Jul. 19, 2012
Loss Contingencies [Line Items]
Rent expense	$ 3,658,000	$ 2,777,000	$ 2,493,000
Performance bonds outstanding	170,500,000
Number of drilling rig commitments	9
Total estimated drilling rig commitment	61,900,000
Energy XXI M21K LLC [Member]
Loss Contingencies [Line Items]
Equity method investment ownership percentage	20.00%			20.00%
Amount of line of credit	100,000,000	100,000,000
April 10, 2014 to October 27, 2014 [Member]
Loss Contingencies [Line Items]
Drilling rig commitment per day	54,448
January 1, 2014 to July 15, 2014 [Member]
Loss Contingencies [Line Items]
Drilling rig commitment per day	107,500
October 1, 2013 to September 1, 2014 [Member]
Loss Contingencies [Line Items]
Drilling rig commitment per day	125,000
March 10, 2014 to March 9, 2015 [Member]
Loss Contingencies [Line Items]
Drilling rig commitment per day	53,175
September 1, 2013 to August 31, 2014 [Member]
Loss Contingencies [Line Items]
Drilling rig commitment per day	140,000
February 15, 2014 to August 15, 2014 [Member]
Loss Contingencies [Line Items]
Drilling rig commitment per day	111,380
April 11, 2014 to September 15, 2014 [Member]
Loss Contingencies [Line Items]
Drilling rig commitment per day	112,000
July 1, 2014 to September 1, 2014 [Member]
Loss Contingencies [Line Items]
Drilling rig commitment per day	107,500
September 1, 2014 to October 1, 2014 [Member]
Loss Contingencies [Line Items]
Drilling rig commitment per day	107,500
Payment Guarantee [Member] | Energy XXI M21K LLC [Member]
Loss Contingencies [Line Items]
Due from related party, commitment period	3 years
LLOG Exploration Offshore [Member] | Payment Guarantee [Member] | Energy XXI M21K LLC [Member]
Loss Contingencies [Line Items]
Due from related party	3,300,000
EP Energy Property [Member] | Payment Guarantee [Member] | Energy XXI M21K LLC [Member]
Loss Contingencies [Line Items]
Due from related party	6,300,000
Eugene Island 330 and South Marsh Island 128 [Member] | Payment Guarantee [Member] | Energy XXI M21K LLC [Member]
Loss Contingencies [Line Items]
Due from related party	1,700,000
Revolving Credit Facility [Member]
Loss Contingencies [Line Items]
Letters of credit	$ 225,700,000

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Derivative Financial Instruments (Fair Values of Derivative Instruments in Consolidated Balance Sheet) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Derivatives, Fair Value [Line Items]
Gross Asset Derivatives	$ 26,975	$ 96,455
Gross Liability Derivatives	58,778	36,180
Total asset amount offset in balance sheet	(22,515)	(36,140)
Total liability amount offset in balance sheet	(22,515)	(36,140)
Derivative asset net amounts presented in Balance Sheet	4,460	60,315
Derivative liability net amounts presented in Balance Sheet	36,263	40
Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Total liability amount offset in balance sheet	(15,955)	(15,803)
Derivative liability net amounts presented in Balance Sheet	31,957	40
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Total liability amount offset in balance sheet	(6,560)	(20,337)
Derivative liability net amounts presented in Balance Sheet	4,306
Current Asset [Member]
Derivatives, Fair Value [Line Items]
Total asset amount offset in balance sheet	(15,955)	(15,803)
Derivative asset net amounts presented in Balance Sheet	1,425	38,389
Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Total asset amount offset in balance sheet	(6,560)	(20,337)
Derivative asset net amounts presented in Balance Sheet	3,035	21,926
Designated as Hedging Instrument [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	47,912	14,609
Designated as Hedging Instrument [Member] | Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	10,866	20,337
Designated as Hedging Instrument [Member] | Current Asset [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	16,829	52,216
Designated as Hedging Instrument [Member] | Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	9,595	42,263
Not Designated as Hedging Instrument [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives		1,234
Not Designated as Hedging Instrument [Member] | Current Asset [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	$ 551	$ 1,976

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Subsequent Events

12 Months Ended

Jun. 30, 2014

Subsequent Events

Note 20 — Subsequent Events

On July 16, 2014, our Board of Directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of our common stock. The quarterly dividend will be paid on September 12, 2014 to shareholders of record on August 29, 2014.

Parent Company [Member]

Subsequent Events

Note 8 – Subsequent Events

     On July 16, 2014, our Board of Directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of our common stock.  The quarterly dividend will be paid on September 12, 2014 to shareholders of record on August 29, 2014.

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Supplemental Cash Flow Information (Supplemental Cash Flow Information) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Cash paid for interest	$ 139,575	$ 99,377	$ 103,346
Cash paid for income taxes	3,641	12,873
Parent Company [Member]
Cash paid for interest	$ 6,767

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Derivative Financial Instruments (Tables)

12 Months Ended

Jun. 30, 2014

Fair Values of Derivative Instruments in Consolidated Balance Sheets

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

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

Schedule of Derivative Instruments Gain (Loss) in Statement of Financial Performance

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

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

Schedule of Cash Flow Hedging Relationship of Derivative Instruments

The cash flow hedging relationship of our derivative instruments was as follows (in thousands):

		Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss,		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss,		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss
		net of tax		net of tax		(Ineffective
Location of (Gain) Loss		(Effective Portion)		(Effective Portion)		Portion)
Year Ended June 30, 2014
Commodity Derivative Instruments	$	47,027
Revenues			$	(6,640)
Loss (gain) on derivative financial instruments					$	6,339
Total	$	47,027	$	(6,640)	$	6,339
Year Ended June 30, 2013
Commodity Derivative Instruments	$	31,051
Revenues			$	(25,876)
Loss (gain) on derivative financial instruments					$	881
Total	$	31,051	$	(25,876)	$	881
Year Ended June 30, 2012
Commodity Derivative Instruments	$	(126,087)
Revenues			$	(22,372)
Loss (gain) on derivative financial instruments					$	(3,479)
Total	$	(126,087)	$	(22,372)	$	(3,479)

Components of AOCI Representing all of the Reclassifications out of AOCI

	Before Tax		After Tax		Location Where Consolidated Net Income is Presented
Year ended June 30, 2014
Unrealized gain on derivatives at beginning of the year	$	(40,851)	$	(26,552)
Unrealized change in fair value during the year		55,794		36,266
Ineffective portion reclassified to earnings during the year		6,339		4,121	Loss on derivative financial instruments
Realized amounts reclassified to earnings during the year		10,215		6,640	Revenues
Unrealized loss on derivatives at the end of the year		31,497		20,475
	Before Tax		After Tax		Location Where Consolidated Net Income is Presented
Year ended June 30, 2013
Unrealized gain on derivatives at beginning of the year	$	(88,620)	$	(57,603)
Unrealized change in fair value during the year		7,078		4,601
Ineffective portion reclassified to earnings during the year		881		573	Loss on derivative financial instruments
Realized amounts reclassified to earnings during the year		39,810		25,887	Revenues
Unrealized gain on derivatives at the end of the year		(40,851)		(26,552)
	Before Tax		After Tax		Location Where Consolidated Net Income is Presented
Year ended June 30, 2012
Unrealized loss on derivatives at beginning of the year	$	105,360	$	68,484
Unrealized change in Fair value during the year		(224,919)		(146,197)
Ineffective portion reclassified to earnings during the year		(3,479)		(2,261)	Loss on derivative financial instruments
Realized amounts reclassified to earnings during the year		34,418		22,371	Revenues
Unrealized gain on derivatives at end of the year	$	(88,620)	$	(57,603)

Crude Oil [Member]

Schedule of Derivative Positions

As of June 30, 2014, we had the following net open crude oil derivative positions:

					Weighted Average Contract Price
					Swaps		Collars/Put Spreads
			Volumes			Sub
Period	Type of Contract	Index	(MBbls)	Fixed Price		Floor		Floor		Ceiling
July 2014 - December 2014	Three-Way Collars	Oil-Brent-IPE	766			$	69.00	$	89.00	$	124.99
July 2014 - December 2014	Put Spreads	Oil-Brent-IPE	431				66.43		86.43
July 2014 - December 2014	Collars	Oil-Brent-IPE	368						90.00		108.38
July 2014 - December 2014	Put Spreads	NYMEX-WTI	1,230				70.00		90.00
July 2014 - December 2014	Put	NYMEX-WTI	460						90.00
July 2014 - December 2014	Roll Swap	NYMEX-WTI	2,295	$	1.03
July 2014 - December 2014	Three-Way Collars	NYMEX-WTI	610				70.00		90.00		137.20
July 2014 - December 2014	Swaps	ARGUS-LLS	1,614		92.84
January 2015 - December 2015	Three-Way Collars	Oil-Brent-IPE	3,650				71.00		91.00		113.75
January 2015 - December 2015	Swaps	Oil-Brent-IPE	548		97.70
January 2015 - December 2015	Collars	ARGUS-LLS	1,825						80.00		123.38
January 2015 - December 2015	Put	NYMEX-WTI	1,813						88.76
January 2015 - December 2015	Roll Swap	NYMEX-WTI	3,180		1.03

Natural Gas [Member]

Schedule of Derivative Positions

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

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

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Related Party Transactions

12 Months Ended

Jun. 30, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Note 13 — Related Party Transactions

We have a 20% interest in EXXI M21K and account for this investment using the equity method.  EXXI M21K is the guarantor of a $100 million line of credit entered into by M21K.  See Note 5 – Equity Method Investments of Notes to Consolidated Financial Statements in this Form 10-K.

We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K for EP Energy Property acquisition estimated at $65 million and $1.8 million, respectively. For the LLOG Exploration acquisition, we guaranteed payment of asset retirement obligations by M21K estimated at $36.7 million.  For the Eugene Island 330 and South Marsh Island 128 properties purchase, we guaranteed payment of asset retirement obligation by M21K estimated at $18.6 million.  For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates.  For the year ended June 30, 2014 and 2013, we have received $3.1 million and $1.9 million, respectively, related to such guarantees. 

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

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

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Supplemental Guarantor Information (Narrative) (Details) (USD $)	12 Months Ended	0 Months Ended
	Jun. 30, 2014	May 27, 2014	Sep. 26, 2013	Dec. 17, 2010	Feb. 25, 2011	Jun. 30, 2013
Debt Instrument [Line Items]
Face value of notes	650,000,000					$ 650,000,000
Debt instrument, stated interest rate	6.875%					6.875%
Energy XXI Gulf Coast Inc [Member]
Debt Instrument [Line Items]
Percentage of ownership of subsidiary by entity	100.00%
6.875% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Face value of notes		650,000,000
Debt instrument, stated interest rate		6.875%
Debt maturity date		Mar. 15, 2024
7.50% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Face value of notes			500,000,000
Debt instrument, stated interest rate			7.50%
Debt maturity date			Dec. 15, 2021
9.25% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Face value of notes				750,000,000
Debt instrument, stated interest rate				9.25%		9.25%
Debt maturity date				Dec. 15, 2017
7.75% Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Face value of notes					$ 250,000,000
Debt instrument, stated interest rate					7.75%	7.75%
Debt maturity date					Jun. 15, 2019