Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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EXHIBIT 99.1

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

C O N T E N T S

		Page

Report of Independent Registered Public Accounting Firm		1

Consolidated Balance Sheets		2

Consolidated Statements of Income		3

Consolidated Statements of Comprehensive Income (Loss)		4

Consolidated Statements of Stockholder’s Equity		5

Consolidated Statements of Cash Flows		6

Notes to Consolidated Financial Statements		7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Energy XXI Gulf Coast, Inc.

We have audited the accompanying consolidated balance sheets of Energy XXI Gulf Coast, Inc. (a Delaware Corporation) and subsidiaries (the “Company”) as of June 30, 2012 and 2011, and the related consolidated statements of income, comprehensive income (loss), stockholder’s equity and cash flows for each of the three fiscal years in the period ended June 30, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated 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 Gulf Coast, Inc. and subsidiaries as of June 30, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three fiscal years in the period ended June 30, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

August 29, 2012

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	June 30,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	45,394		$	-
Receivables:
Oil and natural gas sales		126,107			126,194
Joint interest billings		3,840			4,526
Insurance and other		4,077			1,303
Prepaid expenses and other current assets		51,103			46,429
Derivative financial instruments		32,301			22
TOTAL CURRENT ASSETS		262,822			178,474

Oil and gas properties-net – full cost method of accounting, including $418.8 million and $467.3 million of unevaluated properties not being amortized at June 30, 2012 and 2011, respectively		2,698,213			2,545,336
Other Assets
Deferred taxes		-			51,827
Note receivable from Energy XXI, Inc.		66,099			-
Derivative financial instruments		45,232			-
Debt issuance costs, net of accumulated amortization		26,872			33,479

TOTAL ASSETS	$	3,099,238		$	2,809,116

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	156,388		$	163,723
Accrued liabilities		60,095			53,089
Note payable		22,211			19,853
Asset retirement obligations		34,457			19,624
Derivative financial instruments		-			50,259
Current maturities of long-term debt		3,864			3,798
TOTAL CURRENT LIABILITIES		277,015			310,346

Long-term debt, less current maturities		1,013,523			1,108,912
Deferred taxes		87,229			-
Asset retirement obligations		266,958			303,618
Derivative financial instruments		-			70,524
TOTAL LIABILITIES		1,644,725			1,793,400

COMMITMENTS AND CONTINGENCIES (NOTE 11)

STOCKHOLDER’S EQUITY
Common stock, $0.01 par value, 1,000,000 shares
authorized and 100,000 shares issued and outstanding		1			1
Additional paid-in capital		1,454,081			1,456,517
Accumulated deficit		(57,172	)		(372,318	)
Accumulated other comprehensive income (loss), net of
income taxes		57,603			(68,484	)
TOTAL STOCKHOLDER’S EQUITY		1,454,513			1,015,716

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	3,099,238		$	2,809,116

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands)

	Year Ended June 30,
	2012			2011			2010

REVENUES
Oil sales	$	1,186,631		$	719,683		$	387,935
Natural gas sales		116,772			139,687			110,996
TOTAL REVENUES		1,303,403			859,370			498,931

COSTS AND EXPENSES
Lease operating expense		310,815			239,478			142,612
Production taxes		7,261			3,336			4,217
Gathering and transportation		16,371			12,499			-
Depreciation, depletion and amortization		364,281			290,854			179,040
Accretion of asset retirement obligations		39,161			32,127			23,487
General and administrative expense		79,080			69,711			45,915
Gain on derivative financial instruments		(7,261	)		(5,563	)		(4,739	)
TOTAL COSTS AND EXPENSES		809,708			642,442			390,532

OPERATING INCOME		493,695			216,928			108,399

OTHER INCOME (EXPENSE)
Bridge loan commitment fees		-			(4,500	)		-
Loss on retirement of debt		-			(21,855	)		-
Other income		1,192			120			26,938
Interest expense		(108,731	)		(105,673	)		(92,838	)
TOTAL OTHER EXPENSE		(107,539	)		(131,908	)		(65,900	)

INCOME BEFORE INCOME TAXES		386,156			85,020			42,499

INCOME TAX EXPENSE		71,010			60			5,918

NET INCOME	$	315,146		$	84,960		$	36,581

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)


	Year Ended June 30,
	2012			2011			2010
Net Income	$	315,146		$	84,960		$	36,581
Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		228,398			(136,566	)		35,320
Effective portion reclassified to earnings during the period		(34,418	)		(11,418	)		(48,448	)
Interest Rate Cash Flow Hedges
Reclassified to earnings during the period		-			-			(3,474	)
Total Other Comprehensive Income (Loss)		193,980			(147,984	)		(16,602	)
Income taxes		67,893			(51,794	)		(5,811	)
Net Other Comprehensive Income (Loss)		126,087			(96,190	)		(10,791	)
Comprehensive Income (Loss)	$	441,233		$	(11,230	)	$	25,790

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In Thousands, except share information)


					Additional						Other			Total
	Common Stock				Paid-in			Accumulated			Comprehensive			Stockholder’s
	Shares		Value		Capital			Deficit			Income (Loss)			Equity

Balance, June 30, 2009		100,000	$	1	$	501,935		$	(493,859	)	$	38,497		$	46,574

Contributions from parent						412,532									412,532

Comprehensive income (loss)									36,581			(10,791	)		25,790

Balance, June 30, 2010		100,000		1		914,467			(457,278	)		27,706			484,896

Contributions from parent						542,050									542,050
Comprehensive income (loss)									84,960			(96,190	)		(11,230	)

Balance, June 30, 2011		100,000		1		1,456,517			(372,318	)		(68,484	)		1,015,716

Returns to parent						(2,436	)								(2,436	)

Comprehensive income									315,146			126,087			441,233

Balance, June 30, 2012		100,000	$	1	$	1,454,081		$	(57,172	)	$	57,603		$	1,454,513

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended June 30,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	315,146		$	84,960		$	36,581
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		364,281			290,854			179,040
Deferred income tax expense (benefit)		71,161			(33	)		5,912
Change in derivative financial instruments
Proceeds from sale of derivative instruments		66,522			42,577			5,000
Other		(52,335	)		(37,047	)		(35,633	)
Accretion of asset retirement obligations		39,161			32,127			23,487
Amortization and write-off of debt issuance costs		7,475			15,772			7,806
Amortization of debt discount and premium		148			(43,521	)		(6,872	)
Gain on retirement of debt		-			-			(26,727	)
Payment of interest in-kind		-			2,225			4,009
Changes in operating assets and liabilities:
Accounts receivable		(4,390	)		(49,818	)		(18,307	)
Prepaid expenses and other current assets		(2,316	)		1,278			(12,486	)
Settlements of asset retirement obligations		(14,990	)		(73,974	)		(80,044	)
Accounts payable and other liabilities		(330	)		94,274			15,944
NET CASH PROVIDED BY OPERATING ACTIVITIES		789,533			359,674			97,710

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions		(6,401	)		(1,012,262	)		(19,907	)
Capital expenditures		(565,978	)		(278,324	)		(143,979	)
Insurance payments received		6,472			-			53,985
Proceeds from the sale of properties		2,750			38,431			-
Other-net		3			(9	)		(4	)
NET CASH USED IN INVESTING ACTIVITIES		(563,154	)		(1,252,164	)		(109,905	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		896,717			1,829,828			205,903
Contributions from (returns to) parent		(2,436	)		542,050			40,131
Advances to Energy XXI, Inc.		(66,099	)		-			-
Payments on long-term debt		(1,008,300	)		(1,456,190	)		(294,013	)
Debt issuance costs		(867	)		(29,614	)		(13,030	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(180,985	)		886,074			(61,009	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		45,394			(6,416	)		(73,204	)

CASH AND CASH EQUIVALENTS, beginning of year		-			6,416			79,620

CASH AND CASH EQUIVALENTS, end of year	$	45,394		$	-		$	6,416

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 1 - Organization and Summary of Significant Accounting Policies

Nature of Operations. Energy XXI Gulf Coast, Inc. (“Energy XXI”), a Delaware corporation, was incorporated on February 7, 2006 and is a wholly-owned subsidiary of Energy XXI USA, Inc. (its “Parent”) and an indirect wholly-owned subsidiary of Energy XXI (Bermuda) Limited. We are 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.

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany 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.

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, 2012 and 2011, no allowance for doubtful accounts was necessary.

Oil and 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.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 1 - Organization and Summary of Significant Accounting Policies (Continued)

We evaluate the impairment of our evaluated oil and 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 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 gas reserves. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and 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 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 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. Unamortized premiums of $3.2 million are included in prepaid expenses and other current assets at June 30, 2012.

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 in earnings.

The net cash flows related to any recognized gains or losses associated with cash flow hedges are reported as oil and 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 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 gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and 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.

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, 2012, 2011 and 2010 was $38.3 million, $37.8 million and $26.6 million, respectively.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 1 - Organization and Summary of Significant Accounting Policies (Continued)

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. If positive earnings trends continue or other events occur, the need for retaining this valuation allowance may diminish.

We follow the provisions of ASC Topic 740-10 (formally known as FIN 48, addressing “Uncertain Tax Positions”) and have not recorded any gross unrecognized tax benefits related to Uncertain Tax Positions.

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.

Note 2 - Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-05: Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 provides that an entity that reports items of other comprehensive income has the option to present comprehensive income in either one continuous financial statement or two consecutive financial statements. The update is intended to increase the prominence of other comprehensive income in the financial statements. ASU 2011-05 is effective for annual periods beginning after December 15, 2011, with early adoption permitted. We adopted ASU 2011-05 on June 30, 2012 and the adoption had no effect on our consolidated financial position, results of operations or cash flows other than presentation.

In December 2011, the FASB issued Accounting Standards Update No. 2011-12: Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (ASU 2011-12) . The Update defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. As part of this update, the FASB did not defer the requirement to report comprehensive income either in a single continuous statement or in two separate but consecutive financial statements. ASU 2011-12 is effective for annual periods beginning after December 15, 2011.

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 are currently evaluating the provisions of ASU 2011-11 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 Acquisition

On December 17, 2010, we closed on the acquisition of certain shallow-water Gulf of Mexico shelf oil and natural gas interests from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”). The transaction was funded through a combination of cash on hand, including proceeds from Bermuda’s common and preferred equity offerings, borrowings under our revolving credit facility and proceeds from our $750 million private placement of 9.25% Senior Notes due 2017.

-9-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 3 - Acquisitions and Dispositions (Continued)

Revenues and expenses related to the ExxonMobil Properties from the closing date (December 17, 2010) to June 30, 2011 are included in the June 30, 2011 results of operations.

Pursuant to the Purchase and Sale Agreement (the “PSA”), ExxonMobil reserved a 5% overriding royalty interest in the ExxonMobil Properties for production from depths below approximately 16,000 feet. In addition, the PSA required us to post a $225 million letter of credit, which we posted under our revolving credit facility, in favor of ExxonMobil to guarantee our obligation to plug and abandon the ExxonMobil Properties in the future.

The ExxonMobil Acquisition was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred.

As of December 31, 2011, the Company’s measurement period adjustments were complete. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 17, 2010 (in thousands ):

	December 17, 2010 (As initially reported)			Measurement period adjustment		December 17, 2010 (As adjusted)
Oil and natural gas properties – evaluated	$	926,422		$	—	$	926,422
Oil and natural gas properties – unevaluated		289,711			—		289,711
Net working capital*		101			577		678
Asset retirement obligations		(204,512	)		—		(204,512	)
Cash paid	$	1,011,722		$	577	$	1,012,299

Net working capital includes gas imbalance receivables and payables and ad valorem taxes payable.

The fair values of evaluated and unevaluated oil and gas properties and asset retirement obligation liabilities 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 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) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

Mit Acquisition

On December 22, 2009, we closed on the acquisition of certain Gulf of Mexico shelf oil and natural gas interests from MitEnergy Upstream LLC, a subsidiary of Mitsui & Co., Ltd.(the “Mit Acquisition”), for cash consideration of $276.2 million. For accounting purposes, we recorded this acquisition as effective November 20, 2009, the date that we gained control of the assets acquired and liabilities assumed. We financed the Mit Acquisition through proceeds received from Bermuda’s common and perpetual preferred stock offerings.

The Mit Acquisition was accounted for under the purchase method of accounting. Accordingly, we conducted an assessment of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. Transaction, transition and integration costs associated with this acquisition were expensed as incurred.

The Mit Acquisition involved similar non-operated interests in the same group of properties we purchased from Pogo Producing Company in June 2007. These properties include 30 fields of which production is approximately 77% crude oil and 80% of which we presently operate. Offshore leases included in this acquisition total nearly 33,000 net acres.

-10-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 3 - Acquisitions and Dispositions (Continued)

The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 20, 2009 (in thousands):

Oil and natural gas properties - evaluated	$	292,609
Oil and natural gas properties - unevaluated		41,987
Net working capital		4,237
Asset retirement obligations		(62,604	)
Cash paid	$	276,229

Net working capital includes gas imbalance receivables and payables and ad valorem taxes payable.

The fair values of evaluated and unevaluated oil and gas properties and asset retirement obligations 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 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) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

Sale of Certain Onshore Properties

In June 2011, we closed on the sale of certain onshore oil and natural gas properties for cash consideration of $39.6 million. Revenues and expenses related to the sold properties have been included in our results of operations through the closing dates. The proceeds were recorded as a reduction to our oil and gas properties with no gain or loss being recognized.

Below is a summary of net reduction to the full cost pool related to the sale (in thousands):

Cash received	$	39,625
Reduction of asset retirement obligation related to properties		16,626
Net revenues from June 1, 2011 through closing date		(1,630	)
Adjustment to gas imbalances related to properties		36
Net reduction to the full cost pool	$	54,657

-11-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 4 - Property and Equipment

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

	June 30,
	2012		2011
Oil and gas properties
Proved properties	$	4,375,984	$	3,810,293
Less: accumulated depreciation, depletion, amortization and impairment		2,096,531		1,732,250
Proved properties - net		2,279,453		2,078,043
Unproved properties		418,760		467,293
Oil and gas properties - net	$	2,698,213	$	2,545,336

Note 5 - Long-Term Debt

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

	June 30,
	2012		2011

Revolving credit facility	$	-	$	107,784
9.25% Senior Notes due 2017		750,000		750,000
7.75% Senior Notes due 2019		250,000		250,000
Derivative instruments premium financing		17,387		4,926
Total debt		1,017,387		1,112,710
Less current maturities		3,864		3,798
Total long-term debt	$	1,013,523	$	1,108,912

Maturities of long-term debt as of June 30, 2012 are as follows (in thousands):

Year Ending June 30,

2013	$	3,864
2014		8,032
2015		5,491
2016		-
2017		-
Thereafter		1,000,000
Total	$	1,017,387

Revolving Credit Facility

We entered into the second amended and restated first lien credit agreement (“First Lien Credit Agreement”) in May 2011. This facility has a borrowing capacity of $925 million and matures December 31, 2014. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. At June 30, 2012, the borrowing base was $750 million, which was reaffirmed by the lenders on May 18, 2012. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.25% to 3.00% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves.

-12-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 5 - Long-Term Debt (Continued)

Under the First Lien Credit Agreement, we are prohibited from paying dividends to Bermuda except that we may make payments to Bermuda of up to $25 million in aggregate for the purpose of paying premiums or other payments associated with the early conversion of Bermuda’s preferred stock and we may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that Bermuda may pay dividends on their outstanding preferred stock. On October 4, 2011, we entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement. The First Amendment modified the First Lien Credit Agreement and includes the following: (a) approval for cash distributions by Bermuda of up to $100 million per calendar year, which can be used for various purposes, including stock buybacks, bond repurchases, and/or debt repayments, and is based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds, (b) approval of a cash distribution basket of up to an aggregate of $150 million, to be used for investments and other purposes based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds. Both distribution baskets are further limited by an amount equal to $70 million plus 50% of our Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter and (c) increased the amount of borrowing base availability that must be reserved to deal with potential effects from hurricanes during the period of July 1st to October 31st of each calendar year from $25 million to $50 million.

On May 24, 2012, we entered into the Second Amendment (the “Second Amendment”) to the First Lien Credit agreement which provided further increased flexibility to make payments from us to Bermuda and/or our other subsidiaries. The Second Amendment includes the following: (a) removal of limitations on the ability of us to finance hedge option premiums; and (b) technical modifications in regard to our ability to reposition hedges; (c) adjustment of definitions and other provisions to further increase our ability to make distributions to Bermuda and/or its subsidiaries; and (d) technical corrections in connection with the replacement of one of the lenders (including that lender’s role as an issuer of a letter of credit) under the First Lien Credit Agreement.

The First Lien Credit Agreement (as amended) requires us to maintain certain financial covenants. Specifically, we may not permit the following under First Lien Credit Agreement: (a) our total leverage ratio to be more than 3.5 to 1.0, (b) our interest coverage ratio to be less than 3.0 to 1.0, and (c) our current ratio (in each case as defined in our First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to declare and pay dividends or other payments, our ability to incur debt, changes in control, our 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.

As of June 30, 2012, we were in compliance with all covenants under our First Lien Credit Agreement.

-13-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 5 - Long-Term Debt (Continued)

High Yield Facilities

9.25% Senior Notes

On December 17, 2010, we issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). We 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. We incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

We have the right to redeem the 9.25% Senior Notes under various circumstances and are 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.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of June 30, 2012 was $802.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

Guarantee of 9.25% Notes

We are the issuer of the 9.25% Notes which are fully and unconditionally guaranteed by us, Bermuda and each of our existing and future material domestic subsidiaries. Bermuda and its subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from paying dividends to Bermuda except that we may make payments to Bermuda of up to $25 million in aggregate for the purpose of paying premiums or other payments associated with the early conversion of its preferred stock and we may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that Bermuda may pay dividends on its outstanding preferred stock.

7.75% Senior Notes

On February 25, 2011, we issued $250 million face value of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). We 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. We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

We have the right to redeem the 7.75% Senior Notes under various circumstances and are 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.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of June 30, 2012 was $256.7 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

-14-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 5 - Long-Term Debt (Continued)

Guarantee of 7.75% Notes

We are the issuer of the 7.75% Notes which are fully and unconditionally guaranteed by us, Bermuda and each of our existing and future material domestic subsidiaries. Bermuda and its subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from paying dividends to Bermuda except that we may make payments to Bermuda of up to $25 million in aggregate for the purpose of paying premiums or other payments associated with the early conversion of its preferred stock and we may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that Bermuda may pay dividends on its outstanding preferred stock.

10% Senior Notes

On June 8, 2007, Bermuda completed a private offering of $750 million aggregate principal amount of our 10% Senior Notes due 2013 (the “Old 10% Notes”). On October 16, 2007, it exchanged all of the then issued and outstanding Old 10% Notes for $750 million aggregate principal amount of newly issued 10% Senior Notes due 2013 (the “New Senior Notes”) which had been registered under the Securities Act of 1933, as amended (the “Securities Act”), and contained substantially the same terms as the Old 10% Notes. It did not receive any cash proceeds from the exchange of the Old 10% Notes for the New Senior Notes.

Bermuda previously purchased a total of $126.0 million aggregate principal amount of the New 10% Notes at a cost of $90.9 million, plus accrued interest of $3.3 million for a total cost of $94.2 million, reflecting a total gain of $35.1 million pre-tax. As discussed below, on November 12, 2009, it issued $278 million aggregate principal amount of 16% Second Lien Junior Secured Notes due 2014 (“Second Lien Notes”), in exchange for $347.5 million aggregate principal amount of New 10% Notes. In conjunction with the exchange, it contributed $126 million face value of New 10% Notes which it had previously purchased to us, and we subsequently retired them.

On December 17, 2010, Bermuda called $47.6 million face value of the New 10% at 105% of par plus accrued interest. This transaction closed on January 18, 2011. The $2.38 million difference between the call price and the $47.6 million carrying value of the 10% Second Lien notes was charged to loss on retirement of the New 10% notes in the March 31, 2011 quarter.

On February 10, 2011, Bermuda offered to purchase for cash (the “Tender Offer”), any and all remaining outstanding New 10% Notes at $1,050 per $1,000 principal amount of New 10% Notes (if tendered on or before February 24, 2011) or at $1,020 per $1,000 principal amount of New 10% Notes if tendered after February 24, 2011 but on or before March 10, 2011. A total of $122.3 million face amount of New 10% Notes were tendered by the February 24, 2011 date and an additional $311,130 face value of New 10% Notes were tendered subsequent to February 24, 2011 but on or before March 10, 2011.

On April 18, 2011, Bermuda called the remaining $106.3 million of its New 10% Notes at a call price of 102.5% of par. The redemption closed on June 15, 2011 with full participation.

16% Second Lien Notes

On November 12, 2009, Bermuda issued Second Lien Notes as follows:

·	A total of $278 million of Second Lien Notes were issued in exchange for $347.5 million of New Senior Notes; and

·	A total of $60 million of Second Lien Notes were issued for cash (for each $1.0 million in Second Lien Notes purchased for cash, the purchaser also received 44,082 shares of our common stock).

The Second Lien Notes had a maturity date of June 2014 and were secured by a second lien in our oil and gas properties. In addition, the Second Lien Notes were governed by an inter-creditor agreement between the participants in the revolving credit facility and the Second Lien Notes. Cash interest payable on the Second Lien Notes is 14% with an additional 2% interest payable-in-kind (“Second Lien Note PIK interest”). The Second Lien Note PIK interest was paid through the issuance of additional Second Lien Notes on each interest payment date, with identical terms and conditions to the original Second Lien Notes.

-15-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 5 - Long-Term Debt (Continued)

Under the terms of the Second Lien Notes, Bermuda was required to exchange the Second Lien Notes for newly issued notes registered under the Securities Act (the “Registered Second Lien Notes”). The Registered Second Lien Notes had identical terms and conditions as the Second Lien Notes. On April 5, 2010, Bermuda commenced an offer to exchange the Second Lien Notes for Registered Second Lien Notes. The exchange offer expired on May 3, 2010 and closing was on May 6, 2010. The tendered bonds represented 99.96% of the bonds outstanding.

For accounting purposes, the $278 million aggregate principal amount of Second Lien Notes exchanged for $347.5 million aggregate principal amount of New Senior Notes were recorded at the carrying value of the Registered Second Lien Notes ($347.5 million) and the $69.5 million difference between face value of the Second Lien Notes and carrying value of the New Senior Notes was amortized as a reduction of interest expense over the life of the New Senior Notes.

For accounting purposes, the $60 million aggregate principal amount of Second Lien Notes for which Bermuda received cash were recorded based on the relative fair market values of the Second Lien Notes and the 2.6 million shares of common stock issued using the closing price of $10.60 per share of Bermuda’s common stock on November 12, 2009. Based on these relative fair market values, the $60 million aggregate principal amount of Second Lien Notes was recorded at $40.9 million and the common shares were recorded at $19.1 million. The $19.1 million discount between the face value of the $60 million aggregate principal amount of Second Lien Notes and their recorded value was amortized as an increase in interest expense over the life of the Registered Second Lien Notes.

Refinancing of Existing 16% Second Lien Notes

On November 9, 2010, Bermuda called for redemption of $119.7 million aggregate principal amount of its 16% Second Lien Notes at a redemption price of 110% of the principal amount, plus accrued and unpaid interest, pursuant to the terms of the indenture governing the 16% Second Lien Notes. This redemption closed on December 9, 2010. The total payment of $140.9 million included $9.3 million of accrued interest and $12.0 million in redemption premium.

On November 29, 2010, Bermuda commenced a tender offer for the $222.3 million principal amount of our remaining outstanding 16% Second Lien Notes. In December 2010, a total of $219.9 million face value of 16% Second Lien Notes were tendered. The total payment of $251.0 million included $171,513 of accrued interest and $31.0 million in redemption premium.

On December 17, 2010, Bermuda commenced a call of the remaining outstanding 16% Second Lien Notes which closed on January 18, 2011. In December 2010, it escrowed $5.4 million in funds with the trustee of the 16% Second Lien Notes, which were sufficient to redeem the remaining outstanding notes.

A total of $42.9 million in redemption premiums were paid related to the call and tender of the 16% Second Lien Notes at December 31, 2010.

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedges are done 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, 2012 and June 30, 2011, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $17.4 million and $4.9 million, respectively.

-16-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 5 - Long-Term Debt (Continued)

Interest Expense

For the years ended June 30, 2012, 2011 and 2010, interest expense consisted of the following (in thousands):

	Year Ended June 30,
	2012		2011			2010

Revolving credit facility	$	9,420	$	10,080		$	9,954
9.25% Senior Notes due 2017		69,375		37,193			-
7.75% Senior Notes due 2019		19,375		6,727			-
10% Senior Notes due 2013		-		20,811			45,095
16% Second Lien Notes due 2014		-		24,967			34,330
Amortization of debt issue cost - Revolving credit facility		4,881		6,999			3,015
Amortization of debt issue cost - 10% Senior Notes due 2013		-		1,681			2,522
Amortization of debt issue cost - 16% Second Lien Notes due 2014		-		54			72
Amortization of debt issue cost – 9.25% Senior Notes due 2017		2,206		1,196			-
Amortization of debt issue cost – 7.25% Senior Notes due 2019		388		141			-
Discount amortization - 16% Second Lien Notes due 2014 (Private Placement)		-		1,894			2,605
Premium amortization - 16% Second Lien Notes due 2014 (Exchange Offer)		-		(6,889	)		(9,477	)
Write-off of debt issue costs - Retirement of $126 million in bonds		-		-			1,750
Write-off of debt issue costs – Reduction in revolving credit facility		-		-			447
Derivative instruments premium financing		1,196		819			2,525
Settlement of Lehman Brothers liability		1,890		-			-
	$	108,731	$	105,673		$	92,838

Bridge Loan Commitment Fee

In November 2010, we entered into a Bridge Facility Commitment Letter (the “Bridge Commitment”) with a group of banks to provide a $450 million Bridge Facility, if needed, to acquire the ExxonMobil Properties. The Bridge Commitment required the payment of a commitment fee in the amount of 1% of the full amount of the commitments in respect to the Bridge Facility as well as certain other fees in the event we utilized the Bridge Facility to finance the ExxonMobil Acquisition. We did not utilize the Bridge Facility and paid the banks the $4.5 million commitment fee, which is included in Other Income (Expense).

Note 6 - Notes Payable

In May 2011, we entered into a note with Bank Direct Capital Finance, LLC to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bore interest at an annual rate of 1.93%. The note amortized over ten months. The balance outstanding as of June 30, 2011 was $19.9 million.

In July 2011, 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 $6.3 million and bore interest at an annual rate of 1.93%. The note amortized over the remaining term of the insurance and matured on May 1, 2012.

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 amortizes over the remaining term of the insurance, which matures on December 26, 2012. The balance outstanding as of June 30, 2012 was $22.2 million.

-17-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 7 - Asset Retirement Obligations

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

	Year Ended June 30,
	2012			2011

Balance at beginning of year	$	323,242		$	159,277
Liabilities acquired		125			204,512
Liabilities incurred		2,268			18,086
Liabilities settled		(14,990	)		(73,974	)
Liabilities sold		-			(16,626	)
Revisions in estimated cash flows		(48,391	)		(160	)
Accretion expense		39,161			32,127
Total balance at end of year		301,415			323,242
Less: current portion		34,457			19,624
Long-term balance at end of year	$	266,958		$	303,618

Note 8 - 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, ICE) 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. Historically the basis differential between HLS and WTI has been relatively small and predictable. Over the past five years, HLS has averaged approximately $1 per barrel premium to WTI. Since the beginning of 2011, the HLS/WTI basis differential and volatility has increased with HLS carrying as much as a $30 per barrel premium to WTI. 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.

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.

-18-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 8 - Derivative Financial Instruments (Continued)

We have monetized certain hedge positions and received the following cash proceeds in the following quarters (in thousands):

Quarter Ended	Cash Proceeds
March 31, 2009	$	66,500
March 31, 2010		5,000
September 30, 2010		34,100
December 31, 2010		8,500
September 30, 2011		49,600
December 31, 2011		16,800
March 31, 2012		2,012
	$	182,512

These above monetized amounts were recorded in stockholders’ equity as part of other comprehensive income and are recognized in income over the contract life of the underlying hedge contracts. An additional $0.8 million monetization was captured in the September 30, 2011 quarter with the cash to be received when the underlying hedge contract settles during calendar 2013.

Our future crude oil and natural gas revenue will be increased by the following amounts related to the monetized contracts referred to above (in thousands):

Quarter Ended	Cash (1)		Non-Cash (1)		Total
September 30, 2012	$	9,537	$	-	$	9,537
December 31, 2012		9,046		-		9,046
March 31, 2013		4,821		203		5,024
June 30, 2013		4,858		206		5,064
Thereafter		9,770		416		10,186
	$	38,032	$	825	$	38,857

(1) Cash represents the amounts received through June 30, 2012 as part of the monetization of certain hedge contracts. Non-cash represents monetized hedges in which the cash will be received when the underlying hedge contract settles in calendar year 2013.

-19-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 8 - Derivative Financial Instruments (Continued)

As of June 30, 2012, we had the following contracts outstanding Asset (Liability) and Fair Value Gain (Loss) (in thousands):

	Crude Oil											Natural Gas
						Total										Total				Total
Period	Volume (MBbls)			Contract Price (1)		Asset (Liability)			Fair Value Gain (Loss)			Volume (MMBtu)		Contract Price (1)		Asset (Liability)		Fair Value Gain		Asset (Liability)			Fair Value Gain (Loss) (2)
Crude Oil – WTI Collars
7/12 – 12/12		1,417		$	72.60/$100.19	$	12		$	(404	)									$	12		$	(404	)
1/13 – 12/13		1,664			73.57/105.63		2,149			536											2,149			536
							2,161			132											2,161			132
Three-Way Collars
1/13 – 12/13		1,825			70/90/136.32		11,573			4,134											11,573			4,134
1/14 – 12/14		3,650			70/90/137.14		23,496			8,528											23,496			8,528
							35,069			12,662											35,069			12,662
Put Spreads
7/12 – 12/12		2,760			75.00/85.00		8,210			4,076											8,210			4,076
Swaps
7/12 – 12/12		92			86.60		40			(94	)										40			(94	)
1/13 – 12/13		183			86.60		(326	)		(188	)										(326	)		(188	)
7/12 – 12/12		(92	)		88.20		(187	)													(187	)
1/13 – 12/13		(183	)		88.20		37														37
							(436	)		(282	)										(436	)		(282	)
Crude Oil – Brent Collars
7/12 – 12/12		920			87.00/114.24		848			179											848			179
1/13 – 12/13		2,781			80.00/126.78		7,703			4,491											7,703			4,491
							8,551			4,670											8,551			4,670
Put Spreads
7/12 – 12/12		460			65.00/85.00		(127	)													(127	)
Three-Way Collars
7/12 – 12/12		1,785			67.42/87.42/127.76		3,012			618			5,520	$	4.07/4.93/5.87	$	3,777	$	2,455		6,789			3,073
1/13 – 12/13		1,643			61.67/83.33/140.69		5,385			2,002			10,950		4.07/4.93/5.87		7,009		4,556		12,394			6,558
1/14 – 12/14		1,278			66.43/86.43/141.36		4,922			1,440											4,922			1,440
							13,319			4,060							10,786		7,011		24,105			11,071
Total Gain on Derivatives						$	66,747		$	25,318						$	10,786	$	7,011	$	77,533		$	32,329

(1) The contract price is weighted-averaged by contract volume.

(2) The gain (loss) on derivative contracts is net of applicable income taxes.

-20-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 8 - Derivative Financial Instruments (Continued)

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



	Asset Derivative Instruments						Liability Derivative Instruments
	June 30, 2012			June 30, 2011			June 30, 2012			June 30, 2011
	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	$	66,716	Current	$	6,048	Current	$	34,462	Current	$	58,593
	Non-Current		103,462	Non-Current		1,248	Non-Current		58,229	Non-Current		72,719
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments	Current		46	Current		2,310	Current		-	Current		3
	Non-Current		-	Non-Current		948	Non-Current		-	Non-Current		-
Total		$	170,224		$	10,554		$	92,691		$	131,315

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

	Year Ended June 30,
	2012			2011			2010
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(438	)	$	58,185		$	(4,008	)
Natural gas sales		(28,163	)		(37,874	)		(41,598	)
Total cash settlements		(28,601	)		20,311			(45,606	)
Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments
Ineffective portion of commodity derivative instruments		(3,479	)		(21	)		1,480
Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market gain		(4,542	)		(3,686	)		(11,430	)
Unrealized mark to market (gain) loss		760			(1,856	)		5,211
Total gain on derivative financial instruments		(7,261	)		(5,563	)		(4,739	)
Total (gain) loss	$	(35,862	)	$	14,748		$	(50,345	)

-21-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 8 - Derivative Financial Instruments (Continued)

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, 2012
Commodity Derivative Instruments	$	(126,087	)
Revenues				$	(22,372	)
(Gain) loss on derivative financial instruments							$	(3,479	)
Total	$	(126,087	)	$	(22,372	)	$	(3,479	)
Year Ended June 30, 2011
Commodity Derivative Instruments	$	96,190
Revenues				$	(7,422	)
(Gain) loss on derivative financial instruments							$	(21	)
Total	$	96,190		$	(7,422	)	$	(21	)
Year Ended June 30, 2010
Commodity Derivative Instruments	$	10,791
Revenues				$	(31,491	)
(Gain) loss on derivative financial instruments							$	1,480
Interest Expense					(2,258	)
Total	$	10,791		$	(33,749	)	$	1,480

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $49.7 million ($32.3 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 from 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, 2012, we had no deposits for collateral with our counterparties.

On June 26, 2006, we entered into an interest rate costless collar to mitigate the risk of loss due to changes in interest rates. The dollar amount hedged was $75 million with the interest rate collar being 5.45% to 5.75%. This instrument matured in April 2010. The impact of this collar on interest expense for the year ended June 30, 2010 was an increase of $2.9 million.

-22-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 9 - Supplemental Cash Flow Information

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

	Year Ended June 30,
	2012		2011		2010

Cash paid for interest	$	103,200	$	96,624	$	84,281

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

	Year Ended June 30,
	2012			2011		2010

Derivative instruments premium acquired through financing	$	16,259		$	4,267	$	3,928
Financing of insurance premiums		22,211			19,583		-
Additions to property and equipment by recognizing asset retirement obligations		(45,998	)		222,438		71,635
Oil and gas properties contributed by parent		-			-		273,130
Conversion of affiliate debt to equity		-			-		99,271

Note 10 - Related Party Transactions

During the years ended June 30, 2012, 2011 and 2010, we received (returned) capital contributions of $(2.4) million, $542.1 million and $412.5 million, respectively, from our Parent.

On November 21, 2011, we advanced $65.0 million under a promissory note formalized on December 16, 2011 to Energy XXI, Inc., our indirect parent, bearing a simple interest of 2.78% per annum. The note matures on December 16, 2021. Energy XXI, Inc. has an option to prepay this note in whole or in part at any time, without any penalty or premium. Interest and principal are payable at maturity. Interest on the note receivable amounted to approximately $1,099,000 for the year ended June 30, 2012. Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of June 30, 2012.

The Company has no employees; instead it receives management services from Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company. Other services provided by Energy Services include legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services. Cost of these services for the years ended June 30, 2012, 2011 and 2010 was approximately $77.8 million, $69.6 million and $45.0 million, respectively, and is included in general and administrative expense.

The Company reimbursed $1.1 million to its affiliate Energy XXI Insurance Limited for windstorm insurance coverage. The coverage period is from May 25, 2012 through May 25, 2013. As of June 30, 2012 the unamortized insurance premium of $1.0 million was included in prepaid expenses and other current assets.

Note 11 - 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.

-23-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 11 - Commitments and Contingencies (Continued)

Letters of Credit and Performance Bonds. We had $225.5 million in letters of credit and $25.1 million of performance bonds outstanding as of June 30, 2012.

Drilling Rig Commitments. As of June 30, 2012, we have entered into four drilling rig commitments:

1) November 4, 2011 to January 15, 2013 at $47,800 per day

2) March 10, 2012 to August 6, 2012 at $65,000 per day

3) April 1, 2012 to December 31, 2012 at $75,000 per day

4) June 8, 2012 to August 16, 2012 at $140,000 per day

At June 30, 2012, future minimum commitments under these contracts totaled $32.3 million.

Note 12 - Income Taxes

We are a Delaware company and a member of a consolidated group of corporations for U.S. federal income tax purposes where Energy XXI USA, Inc., (the “U.S. Parent”) is the parent entity. Energy XXI (Bermuda) Limited (the “Foreign Parent”) indirectly owns 100% of U.S. Parent. ASC Topic 740 (formerly SFAS No. 109) provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated group should be based upon a consistent, reasonable allocation of the income tax amounts of the consolidated group. Accordingly, the income tax amounts presented herein have been computed by applying the provisions of Topic 740 to Energy XXI and its subsidiaries as if it were a separate consolidated group.

We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon the tax laws and rates of the United States as they apply to our current ownership structure.

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

	Year Ended June 30,
	2012			2011			2010

Current	$	(53	)	$	93		$	6
Deferred		71,063			(33	)		5,912
Income tax expense	$	71,010		$	60		$	5,918

-24-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 12 - Income Taxes (Continued)

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

	Year Ended June 30,
	2012			2011			2010

Income (loss) before income taxes	$	386,156		$	85,020		$	42,499
Statutory rate		35	%		35	%		35	%
Income tax expense (benefit) computed at statutory rate		135,155			29,757			14,875
Reconciling items:
State income taxes, net of federal tax benefit		(53	)		60			4
Change in valuation allowance, net		19,334			(23,770	)		(49,562	)
Revaluation of tax attribute carryovers		(33,337	)		(5,989	)		-
Cancellation of debt income – GC bond repurchase		(50,316	)		-			(12,289	)
Cancellation of debt income – contributed GC bonds		-			-			(2,562	)
Cancellation of debt income – 2nd Lien Notes		-			-			55,311
Other		227			2			141
Income tax expense	$	71,010		$	60		$	5,918

-25-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 12 - 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 (in thousands):

	June 30,
	2012			2011
Deferred tax assets:
Asset retirement obligations	$	105,237		$	13,029
Tax loss carryforwards		220,202			57,431
Oil and gas properties		-			24,318
Derivative instruments		-			47,310
Deferred state taxes		20,034			5,479
Deferred interest under IRC Sec. 163(j)		60,403			-
Total deferred tax assets		405,876			147,567

Deferred tax liabilities:
Derivative instruments		17,938			-
Oil and gas properties		351,933			-
Retirement of debt		9,680			4,184
Tax Partnership activity		31,159			16,468
Other		47			12,074
Total deferred tax liabilities		410,757			32,726

Valuation allowance		82,348			63,014

Net deferred tax asset (liability)	$	(87,229	)	$	51,827

At June 30, 2012, the U.S. consolidated tax group had a federal tax loss carryforward (“NOLs”) of approximately $648.4 million and a state income tax loss carryforward of approximately $385.3 million, which will expire in various amounts beginning in 2026 and ending in 2029. As of June 30, 2012, Energy XXI Gulf Coast, Inc. was the primary contributor of the federal and state loss carryforwards to the U.S. consolidated tax group.

-26-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 12 - 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 3.0% and 4.5%). 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. 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 attribute carryforwards and will reassess realization of these carryforwards periodically.

During the year ended June 30, 2009, we incurred a significant 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, for the year ending June 30, 2012, we are in a position of cumulative reporting losses for the preceding reporting periods. The volatility of energy prices and uncertainty of when energy prices may rebound is problematic and not readily determinable by our management. At this date, this general fact pattern does not allow us to project sufficient sources of future taxable income to offset our tax loss carryforwards and net deferred tax assets in the U.S. Under these current circumstances, it is management’s opinion that the realization of these tax attributes beyond the reversal of existing taxable temporary differences does not reach the “more likely than not” criteria under Topic 740. As a result, during the year ended June 30, 2009 the consolidated group established a valuation allowance of $175.0 million, and adjusted this allowance downward by $92.7 million due principally to the presence of pre-tax income in the subsequent years. This results in an ending valuation allowance of $82.3 million at June 30, 2012. 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 U.S. parent adopted the provisions of ASC 740-10 (formally known as FIN 48) and applied the guidance of Topic 740-10 as of July 1, 2007. As of the adoption date, our parent did not record a cumulative effect adjustment related to the adoption of Topic 740-10 or have any gross unrecognized tax benefit. At June 30, 2012, our parent did not have any Topic 740-10 liability or gross unrecognized tax benefit.

The U.S. parent filed our initial tax return for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 through 2011. Tax years ended June 30, 2009 through 2011 remain open to examination under the applicable statute of limitations in the U.S. and state tax jurisdictions in which the Company and its affiliates 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.

The U.S. consolidated group historically has paid no (significant) cash taxes primarily due to the presence of our NOLs. However, if current income trends continue, we could be responsible for making cash tax payments in fiscal 2014 from application of the alternative minimum tax (AMT) under current law.

-27-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 13 - 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 32%, 61% and 62% of our total oil and natural gas revenues during the years ended June 30, 2012, 2011 and 2010, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 37% and 22% of our total oil and natural gas revenues during the years ended June 30, 2012 and 2011, respectively. J.P. Morgan Ventures Energy Corporation (“J.P. Morgan”) accounted for 18% of our total oil and natural gas revenues during the year ended June 30, 2012. 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, ExxonMobil and or J.P. Morgan 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 14 - 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 8 - Derivative Financial Instruments.

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.

-28-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 14 - Fair Value of Financial Instruments (Continued)

The following table presents the fair value of our Level 2 financial instruments (in thousands):

	Level 2
	June 30,
	2012		2011
Assets:
Oil and natural gas derivatives	$	170,224	$	10,554
Liabilities:
Oil and natural gas derivatives	$	92,691	$	131,315

Note 15 - Prepayments and Accrued Liabilities

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

	June 30,
	2012		2011

Prepaid expenses and other current assets
Advances to joint interest partners	$	12,966	$	14,696
Insurance		30,162		22,972
Inventory		4,849		6,305
Royalty deposit		2,443		1,959
Other		683		497
Total prepaid expenses and other current assets	$	51,103	$	46,429

Accrued liabilities
Advances from joint interest partners	$	301	$	437
Interest payable		3,721		5,806
Accrued hedge payable		136		14,095
Undistributed oil and gas proceeds		54,484		31,880
Other		1,453		871
Total accrued liabilities	$	60,095	$	53,089

Note 16 - Subsequent Event

In July 2012, we entered into a note to finance a portion of our insurance premiums. The note is for a total face amount of $3.6 million and bears interest at an annual rate of 1.667%. The note amortizes over the remaining term of the insurance, which matures May 1, 2013.

-29-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 17 - 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,
	2012			2011		2010
	(In Thousands)
Oil and Gas Activities
Exploration costs	$	183,397		$	98,133	$	51,030
Development costs		382,581			180,191		92,949
Total capital expenditures		565,978			278,324		143,979
Property acquisitions
Proved		6,401			722,551		250,795
Unproved		-			289,711		42,242
Total acquisitions		6,401			1,012,262		293,037
Asset retirement obligations, insurance proceeds and other - net		(55,221	)		205,702		17,996
Total costs incurred	$	517,158		$	1,496,288	$	455,012

Oil and natural gas property costs excluded 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 relative 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 unproved property costs and major development projects:

	June 30,
	2012		2011		2010
	(In Thousands)

Unevaluated properties	$	166,692	$	324,549	$	85,211
Wells in progress		252,068		142,744		59,099
	$	418,760	$	467,293	$	144,310

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 third-party reservoir engineers. 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.

-30-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 17 - Supplementary Oil and Gas Information - Unaudited (Continued)

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

	Crude Oil (MBbls)			Natural Gas (MMcf)			Total (MBOE)
Proved reserves at June 30, 2009		30,873			133,415			53,109
Production		(5,352	)		(15,534	)		(7,941	)
Extensions and discoveries		698			5,637			1,638
Revisions of previous estimates		3,643			7,403			4,877
Purchases of minerals in place		17,621			37,862			23,931
Proved reserves at June 30, 2010		47,483			168,783			75,614
Production		(8,553	)		(24,533	)		(12,642	)
Extensions and discoveries		3,056			39,555			9,649
Revisions of previous estimates		2,155			(43	)		2,148
Reclassification of proved undeveloped		(2,917	)		(4,579	)		(3,681	)
Purchases of minerals in place		37,115			97,591			53,380
Sales of reserves		(1,133	)		(40,458	)		(7,876	)
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


Proved developed reserves
June 30, 2009	20,183	82,432	33,922
June 30, 2010	36,970	93,610	52,572
June 30, 2011	59,234	134,024	81,572
June 30, 2012	63,308	110,310	81,693
Proved undeveloped reserves
June 30, 2009	10,690	50,983	19,187
June 30, 2010	10,513	75,173	23,042
June 30, 2011	17,972	102,292	35,020
June 30, 2012	21,485	98,680	37,931

Proved undeveloped (“PUD”) reserve estimates of 37,931 MBOE as of June 30, 2012 increased by 8% over the 35,020 MBOE of PUD reserves estimated at the end of June 30, 2011. During fiscal 2012, 1.6 MMBOE of previously proved undeveloped reserves were converted to proved developed reserves principally through drilling activity in West Delta 73 and South Timbalier 54.

During fiscal 2012, a total of $24.3 million was spent on projects associated with reserves that were carried as PUD reserves at the end of fiscal year 2011.

Four PUDs were not converted into proved developed reserves within the five year requirement at June 30, 2012. Main Pass 61 OCS-G 16493 A-3 and Main Pass 73 B-19 ST are both sidetrack PUDs, but are still producing and cannot be drilled until the PDP zone in each well depletes. South Pass 49 OCS-G 2177 A-2 ST and A-10 ST were not converted because SP 49’s “A” platform is located in a mudslide area and had not been certified for drilling until May 2012, when Bureau of Safety and Environmental Enforcement (“BSEE”) certified that the platform met conditions for acceptance criteria.

During the year ended June 30, 2012 proved reserve estimates were reduced by 2.1 MMBOE from one PUD, ST 21 Chardonnay, due to the five year development rule.

-31-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 17 - Supplementary Oil and Gas Information - Unaudited (Continued)

Standardized Measure of Discounted Future Net Cash Flows

A summary of the standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves is shown below. Future cash inflows as of June 30, 2012 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $115.08 per barrel of oil (calculated using the unweighted average first-day-of-the-month Heavy Louisiana Sweet posted prices during the 12-month period ending on June 30, 2012). 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 $113.36 per barrel of oil and $56.92 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials.

The $113.36 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $95.67 per barrel (differential of +$17.69 per barrel), and an unweighted average first-day-of-the-month Brent price of $112.49 per barrel (differential of +$0.87 per barrel)

For natural gas, the average Henry Hub price used was $3.15 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 gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $3.296 per MCF after adjusting for energy content, transportation fees, and regional price differentials.

For the years ended June 30, 2011 and 2010, West Texas Intermediate crude oil prices used were $90.09 per barrel and $75.76 per barrel, respectively and Henry Hub natural gas prices used were $4.21 per MMBtu and 4.10 per MMBtu, respectively. We used costs and statutory tax rates (adjusted for tax credits and other items) that relate to our existing proved crude oil and natural gas reserves.

The standardized measure of discounted future net cash flows related to proved oil and gas reserves as of June 30, 2012, 2011 and 2010 are as follows (in thousands):

	June 30,
	2012		2011		2010
Future cash inflows	$	10,009,119	$	7,989,182	$	4,121,293
Less related future
Production costs		2,737,969		2,188,918		1,024,492
Development and abandonment costs		1,304,007		1,184,728		639,524
Income taxes		1,377,363		1,073,278		398,399
Future net cash flows		4,589,780		3,542,258		2,058,878
Ten percent annual discount for estimated timing of cash flows		1,284,291		980,865		509,727
Standardized measure of discounted future net cash flows	$	3,305,489	$	2,561,393	$	1,549,151

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2012 AND 2011

Note 17 - Supplementary Oil and Gas Information - Unaudited (Continued)

Changes in Standardized Discounted Future Net Cash Flows

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

	Year Ended June 30,
	2012			2011			2010
Beginning of year	$	2,561,393		$	1,549,151		$	1,005,276
Revisions of previous estimates
Changes in prices and costs		855,382			362,283			300,591
Changes in quantities		153,537			59,149			27,735
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		604,266			111,053			27,651
Purchases of reserves in place		-			1,553,858			703,456
Sales of reserves in place		-			(171,264	)		-
Accretion of discount		333,748			184,892			105,977
Sales, net of production and gathering and transportation costs		(968,956	)		(604,057	)		(352,102	)
Net change in income taxes		(215,873	)		(476,319	)		(245,269	)
Changes in rate of production		(13,438	)		(72,069	)		(31,104	)
Development costs incurred		24,519			114,710			108,864
Changes in abandonment costs and other		(29,089	)		(49,994	)		(101,924	)
Net change		744,096			1,012,242			543,875
End of year	$	3,305,489		$	2,561,393		$	1,549,151

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Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - August 29, 2012

Attached files

Energy XXI Ltd Reports