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, 2011 AND 2010

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

C O N T E N T S

	Page

Independent Auditors’ Report		1

Consolidated Balance Sheets		2

Consolidated Statements of Operations		3

Consolidated Statements of Stockholder’s Equity		4

Consolidated Statements of Cash Flows		5

Notes to Consolidated Financial Statements		6

INDEPENDENT AUDITORS’ REPORT

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, 2011 and 2010, and the related consolidated statements of operations, stockholder’s equity and cash flows for each of the three fiscal years in the period ended June 30, 2011. 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, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three fiscal years in the period ended June 30, 2011, in conformity with accounting principles generally accepted in the United States of America.

/S/ UHY LLP

Houston, Texas

September 1, 2011

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	June 30,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	-		$	6,416
Receivables:
Oil and natural gas sales		126,194			68,675
Joint interest billings		4,526			4,388
Insurance and other		1,303			3,168
Prepaid expenses and other current assets		44,470			25,514
Royalty deposit		1,959			2,341
Derivative financial instruments		22			19,757
TOTAL CURRENT ASSETS		178,474			130,259

Oil and gas properties – full cost method of accounting, including $467.3 million and $144.3 million unevaluated properties at June 30, 2011 and 2010, respectively, net of accumulated depreciation, depletion, amortization and impairment		2,545,336			1,378,222
Other Assets
Deferred taxes		51,827			-
Derivative financial instruments		-			14,610
Debt issuance costs, net of accumulated amortization		33,479			19,637

TOTAL ASSETS	$	2,809,116		$	1,542,728

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	163,723		$	84,802
Accrued liabilities		53,089			37,738
Note payable		19,853			-
Asset retirement obligations		19,624			35,154
Derivative financial instruments		50,259			1,701
Current maturities of long-term debt		3,798			2,317
TOTAL CURRENT LIABILITIES		310,346			161,712

Long-term debt, less current maturities		1,108,912			771,486
Asset retirement obligations		303,618			124,123
Derivative financial instruments		70,524			511
TOTAL LIABILITIES		1,793,400			1,057,832

COMMITMENTS AND CONTINGENCIES (NOTE 13)

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		1,456,517			914,467
Accumulated deficit		(372,318	)		(457,278	)
Accumulated other comprehensive income (loss), net of
income tax expense (benefit)		(68,484	)		27,706
TOTAL STOCKHOLDER’S EQUITY		1,015,716			484,896

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	2,809,116		$	1,542,728

See accompanying Notes to Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands)

	Year Ended June 30,
	2011			2010			2009

REVENUES
Oil sales	$	719,683		$	387,935		$	292,763
Natural gas sales		139,687			110,996			141,067
TOTAL REVENUES		859,370			498,931			433,830

COSTS AND EXPENSES
Lease operating expense		251,977			142,612			122,150
Production taxes		3,336			4,217			5,450
Impairment of oil and gas properties		-			-			576,996
Depreciation, depletion and amortization		290,854			179,040			214,641
Accretion of asset retirement obligations		32,127			23,487			14,635
General and administrative expense		69,711			45,915			21,171
Loss (gain) on derivative financial instruments		(5,563	)		(4,739	)		(10,147	)
TOTAL COSTS AND EXPENSES		642,442			390,532			944,896

OPERATING INCOME (LOSS)		216,928			108,399			(511,066	)

OTHER INCOME (EXPENSE)
Bridge loan commitment fees		(4,500	)		-			-
Loss on retirement of debt		(21,855	)		-			-
Other income		120			26,938			872
Interest expense		(105,673	)		(92,838	)		(94,019	)
TOTAL OTHER EXPENSE		(131,908	)		(65,900	)		(93,147	)

INCOME (LOSS) BEFORE INCOME TAXES		85,020			42,499			(604,213	)

INCOME TAX EXPENSE (BENEFIT)		60			5,918			(50,006	)

NET INCOME (LOSS)	$	84,960		$	36,581		$	(554,207	)

See accompanying Notes to Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In Thousands, except share information)

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

Balance, June 30, 2008		100,000	$	1	$	436,301	$	60,348		$	(285,010	)	$	211,640

Contributions from parent						65,634								65,634
Comprehensive income (loss):
Net loss								(554,207	)					(554,207	)
Unrealized gain on derivative financial instruments, net of income taxes											323,507			323,507
Total comprehensive loss														(230,700	)

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):
Net income								36,581						36,581
Unrealized loss on derivative financial instruments, net of income tax benefit											(10,791	)		(10,791	)
Total comprehensive income														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):
Net income								84,960						84,960
Unrealized loss on derivative financial instruments, net of income tax benefit											(96,190	)		(96,190	)
Total comprehensive loss														(11,230	)

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

See accompanying Notes to Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended June 30,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	84,960		$	36,581		$	(554,207	)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		290,854			179,040			214,641
Impairment of oil and gas properties		-			-			576,996
Deferred income tax expense (benefit)		(33	)		5,912			(50,006	)
Change in derivative financial instruments
Proceeds from sale of derivative instruments		42,577			5,000			66,480
Other		(37,047	)		(35,633	)		(19,549	)
Accretion of asset retirement obligations		32,127			23,487			14,635
Amortization and write-off of debt issuance costs		15,772			7,806			5,245
Amortization of debt discount and premium		(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		(49,818	)		(18,307	)		91,174
Prepaid expenses and other current assets		1,278			(12,486	)		1,599
Settlements of asset retirement obligations		(73,974	)		(80,044	)		(25,421	)
Accounts payable and other liabilities		94,274			15,944			(80,778	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		359,674			97,710			240,809

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions		(1,012,262	)		(19,907	)		-
Capital expenditures		(278,324	)		(143,979	)		(264,316	)
Insurance payments received		-			53,985			-
Proceeds from the sale of properties		38,431			-			3,233
Other-net		(9	)		(4	)		(221	)
NET CASH USED IN INVESTING ACTIVITIES		(1,252,164	)		(109,905	)		(261,304	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		1,829,828			205,903			270,794
Contributions from parent		542,050			40,131			65,634
Payments on long-term debt		(1,456,190	)		(294,013	)		(236,707	)
Debt issuance costs		(29,614	)		(13,030	)		(2,270	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		886,074			(61,009	)		97,451

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(6,416	)		(73,204	)		76,956

CASH AND CASH EQUIVALENTS, beginning of year		6,416			79,620			2,664

CASH AND CASH EQUIVALENTS, end of year	$	-		$	6,416		$	79,620

See accompanying Notes to Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

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. Energy XXI (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company, 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. Our consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries. 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 net income (loss), stockholder’s equity or cash flows.

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. 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 the full cost pool as the properties are evaluated or over the life of the reservoir.

We evaluate the impairment of our evaluated oil and 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 significant revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict. As discussed in Note 3, we recorded a write-down to our oil and gas properties in the second and third quarters of fiscal 2009.

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.

Use of Estimates. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of 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. While we believe that the estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

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.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

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

Business Segment Information. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses, separate financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Our operations involve the exploration, development and production of oil and natural gas and are entirely located in the United States of America. We have a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments.

Allowance for Doubtful Accounts. We establish provisions for losses on accounts receivables 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, 2011 and 2010, no allowance for doubtful accounts was necessary.

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 and amortization (“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.

Capitalized Interest. Oil and natural gas investments in significant unproved properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs. Capitalized interest cannot exceed gross interest expense. As excluded oil and natural gas costs are transferred to the depreciable base, the associated capitalized interest is also transferred. For the years ended June 30, 2011, 2010 and 2009, we have not capitalized any interest expense.

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 significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

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.

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 deferred and 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.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

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.

In light of our capital structure, US 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 US withholding tax ( at 30%) is due when the interest is actually paid, and may not be offset or reduced by US operating activity; although the interest expense is generally deductible in the US when paid, subject to certain other limitations.

We adopted the provisions of ASC 740-10 (formally known as FIN 48) and applied the guidance of ASC 740-10 as of July 1, 2007. As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of ASC 740-10 or have any gross unrecognized tax benefit. At June 30, 2011, we did not have any ASC 740-10 liability or gross unrecognized tax benefit. As part of the adoption of this guidance, we will record income tax related interest and penalties as a component of income tax expense.

Subsequent Events. We evaluate events and transactions occurring after the balance sheet date and through the date the consolidated financial statements are available to be issued. We evaluated such events and transactions through September 1, 2011, which is the date our consolidated financial statements were available for issuance.

Note 2 - Recent Accounting Pronouncements

We disclose the existence and potential effect of accounting standards issued but not yet adopted by us or recently adopted by us with respect to accounting standards that may have an impact on us in the future.

Presentation of Comprehensive Income. The FASB has issued new guidance on the presentation of comprehensive income. This new guidance allows an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. This guidance eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders' equity. The new guidance does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. Components of comprehensive income are stated net of income tax at 35%, subject to evaluations for the need for a valuation allowance against any resulting deferred tax asset(s).

This new guidance will be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 2 - Recent Accounting Pronouncements (Continued)

Fair Value Measurements and Disclosures. The FASB has issued new guidance on improving disclosures about fair value measurements. The new guidance requires certain new disclosures and clarifies some existing disclosure requirements about fair value measurement. The FASB’s objective is to improve these disclosures and, thus, increase the transparency in financial reporting. Specifically, the new guidance requires:

·	A reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and

·	In the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements.

In addition, the new guidance clarifies the requirements of the following existing disclosures:

·	For purposes of reporting fair value measurement for each class of assets and liabilities, a reporting entity needs to use judgment in determining the appropriate classes of assets and liabilities; and

·	A reporting entity should provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements.

The new guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. We adopted the new guidance effective January 1, 2010. The implementation of this standard did not have a material impact on our consolidated financial position and results of operations.

Updates to Oil and Gas Accounting Rules. In January 2010, the FASB issued its updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive Industries—Oil and Gas with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008. We adopted the new rules effective June 30, 2010. The new rules are applied prospectively as a change in estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.

The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology. Revised requirements in the final rule include, but are not limited to:

·	Oil and gas reserves must be reported using the average price over the prior 12-month period, rather than year-end prices;

·	Companies are allowed to report, on an optional basis, probable and possible reserves;

·	Non-traditional reserves, such as oil and gas extracted from coal and shales, are included in the definition of “oil and gas producing activities”;

·	Companies are permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 2 - Recent Accounting Pronouncements (Continued)

Companies are required to disclose, in narrative form, additional details on their proved undeveloped reserves (PUDs), including the total quantity of PUDs at year end, any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs;

·	Companies are required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing the reserves estimates.

Note 3 - Impairment of Oil and Gas Properties

Ceiling Test. Under the full cost method of accounting, we are required to perform each quarter, a “ceiling test” that determines a limit on the book value of our oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10%, net of related tax effects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. Future net cash flows are based on the average commodity prices realized over the preceding twelve-month period and exclude future cash outflows related to estimated abandonment costs. As of the reported balance sheet date, capitalized costs of an oil and gas producing company may not exceed the full cost limitation calculated under the above described rule. However, if prior to the balance sheet date, the company enters into certain hedging arrangements for a portion of its future natural gas and oil production, thereby enabling the company to receive future cash flows that are higher than the estimated future cash flows indicated, these higher hedged prices are used if they qualify as cash flow hedges.

Because of the decline in crude oil and natural gas prices, coupled with the impact of Hurricanes Gustav and Ike, we recognized a non-cash write-down of the net book value of our oil and gas properties of $117.9 million and $459.1 million in the third and second quarters of fiscal 2009, respectively. The write-downs were reduced by $179.9 million and $203.0 million pre-tax as a result of our hedging program in the third and second quarters of fiscal 2009, respectively. No write-downs were required for any of the periods of fiscal 2011 or 2010.

Note 4 - 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 against our $700 million corporate revolver, as amended, and proceeds from our $750 million private placement of 9.25% Senior Notes due 2017.

The ExxonMobil Acquisition was accounted for under the purchase method of accounting. Accordingly, we conducted a preliminary assessment of the net assets acquired and recognized provisional 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 accounting for the business combination is not complete; adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as we complete a more detailed analysis of this acquisition and additional information is obtained about the facts and circumstances that existed as of the acquisition date.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 4 - 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 following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 17, 2010 (in thousands):

Oil and natural gas properties - evaluated	$	926,422
Oil and natural gas properties - unevaluated		289,711
Net working capital		101
Asset retirement obligations		(204,512	)
Cash paid	$	1,011,722

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

The preliminary 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.

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

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 4 - Acquisitions and Dispositions (Continued)

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.

The following amounts of the ExxonMobil Properties’ revenue and earnings are included in our consolidated statement of operations for the year ended June 30, 2011 and the summarized unaudited pro forma financial information for the years ended June 30, 2011 and 2010, respectively, assumes that the ExxonMobil and Mit Acquisitions had occurred on July 1, 2009. These unaudited pro forma financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if we had completed each acquisition as of the earlier date or the results that will be attained in the future (in thousands):

	Revenue		Earnings (1)

ExxonMobil Acquisition properties from December 17, 2010 through June 30, 2011	$	226,232	$	163,896

ExxonMobil and Mit Acquisitions properties

Supplemental pro forma for July 1, 2010 through June 30, 2011		1,031,104		730,652

Supplemental pro forma for July 1, 2009 through June 30, 2010		961,070		694,775

(1)	Earnings includes revenue less production costs.

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

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 5 - Property and Equipment

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

	June 30,
	2011		2010
Oil and gas properties
Proved properties	$	3,810,293	$	2,675,308
Less: accumulated depreciation, depletion, amortization and impairment		1,732,250		1,441,396
Proved properties - net		2,078,043		1,233,912
Unproved properties		467,293		144,310
Oil and gas properties - net	$	2,545,336	$	1,378,222

Note 6 - Long-Term Debt

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

	June 30,
	2011		2010

Revolving credit facility	$	107,784	$	109,457
9.25% Senior Notes due 2017		750,000		-
7.75% Senior Notes due 2019		250,000		-
10% Senior Notes due 2013		-		276,500
16% Second Lien Notes due 2014 (Exchange Offer)		-		341,319
16% Second Lien Notes due 2014 (Private Placement)		-		44,210
Put premium financing		4,926		2,317
Total debt		1,112,710		773,803
Less current maturities		3,798		2,317
Total long-term debt	$	1,108,912	$	771,486

Maturities of long-term debt as of June 30, 2011 are as follows (in thousands):

Year Ending June 30,

2012	$	3,798
2013		1,128
2014		-
2015		107,784
2016		-
Thereafter		1,000,000
Total	$	1,112,710

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 6 - Long-Term Debt (Continued)

Revolving Credit Facility

This facility, as amended and restated, 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. The current borrowing base is $750 million. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, 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.

The revolving credit facility requires us to maintain certain financial covenants. Specifically, we may not permit the following under the revolving credit facility: (1) Our total leverage ratio to be more than 3.5 to 1.0, (2) EGC’s interest coverage ratio to be less than 3.0 to 1.0, and (3) Our current ratio (in each case as defined in our revolving credit facility) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, our indirect Parent is subject to various other covenants including, but not limited to, those limiting their 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, 2011, we are in compliance with all covenants.

On October 15, 2010, we and our lenders entered into the Seventh Amendment to Amended and Restated First Lien Credit Agreement (“Seventh Amendment”). The Seventh Amendment modifications to the First Lien Credit Agreement include:

Allowing the establishment of a Swing Line Loan Commitment in an amount initially set at $15 million which is carved out of the First Lien Credit Agreement borrowing base. The amounts ultimately available under the Swing Line can be adjusted upward or downward by the lenders and us under certain conditions.

·	Allowing for a one-time payment by us to our indirect Parent or its subsidiaries of up to $25 million for the purpose of paying premiums or other payments associated with inducing the early conversion of its 7.25% preferred stock.

·	Allowing payments by us to our indirect Parent or its subsidiaries of up to $9 million in any calendar year, subject to certain terms and conditions, so that it may pay dividends on its outstanding preferred stock.

On November 17, 2010, we entered into an Eighth Amendment to Amended and Restated First Lien Credit Agreement to our revolving credit facility (the “Eighth Amendment”). The Eighth Amendment modifies the First Lien Credit Agreement and includes the following:

·	Increasing the debt incurrence provisions to allow for an incremental unsecured debt basket of up to $1.0 billion;

·	Increasing the borrowing base to $700 million;

·	Increasing notional amount of the revolving credit facility to $925 million;

·	Increasing the letter of credit sublimit to $300 million; and

·	Extending the maturity date to December 31, 2014, (March 31, 2013 if any of the 10% Senior Notes remain outstanding).

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 6 - Long-Term Debt (Continued)

The Eighth Amendment was deemed effective when all conditions precedent had been met, including the closing of the ExxonMobil Acquisition. All of these conditions were met on December 17, 2010.

On May 5, 2011, we entered into the Second Amended and Restated First Lien Credit Agreement “Second Amended and Restated Agreement”), which replaces the Amended and Restated First Lien Credit Agreement and all of its amendments. The Second Amended and Restated Agreement incorporated all of the modifications contained in the Seventh Amendment and Eighth Amendment listed above, and includes additional modifications:

·	Increasing the borrowing base to $750 million;

·	Increasing the debt incurrence provisions to allow for the issuance of an incremental $250 million of unsecured debt;

Reducing the applicable margin ranges by 0.50%, therefore setting the interest on borrowing base usage at the applicable London Interbank Offered Rate, 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%;

·	Eliminating the covenant that our secured debt ratio not exceed 2.5 to 1.0;

Allowing for payments by us to our indirect Parent or its subsidiaries of up to $25 million in aggregate (including those in the aggregate total amount of $11,082,156 made to date) for the purpose of paying premiums or other payments associated with inducing the early conversion of our preferred stock;

·	Allowing payments by EGC to us or our subsidiaries of up to $17 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock; and

·	Allowing the creation of the insurance affiliate as our subsidiary.

High Yield Facilities

9.25% Senior Notes

On December 17, 2010, EGC issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). We exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes registered under the Securities Act of 1933 (the “9.25% Senior Notes”) 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 will be lifted on December 17, 2011, one year from the original issuance date.

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.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 6 - Long-Term Debt (Continued)

The 9.25% Senior Notes are guaranteed by our indirect Parent and each of its existing and future material domestic subsidiaries. Our Parent 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, 2011 was $780.0 million.

Guarantee of 9.25% Notes

We are the issuer of the 9.25% Notes which are fully and unconditionally guaranteed by indirect Parent. Our indirect Parent and its subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from paying dividends to our indirect Parent except that we may make payments of up to $25 million in aggregate (including those in the aggregate total amount of $11,082,156 made to date) 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 it 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 of 1933 (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.

The 7.75% Senior Notes are guaranteed by our indirect Parent and each of our existing and future material domestic subsidiaries. Our indirect Parent has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of June 30, 2011 was $241.3 million.

Guarantee of 7.75% Notes

We are the issuer of the 7.75% Notes which are fully and unconditionally guaranteed by indirect Parent. Our indirect Parent and its subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from paying dividends to our indirect Parent except that we may make payments of up to $25 million in aggregate (including those in the aggregate total amount of $11,082,156 made to date) 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 it may pay dividends on its outstanding preferred stock.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 6 - Long-Term Debt (Continued)

10% Senior Notes

On June 8, 2007, our indirect Parent 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.

Our indirect Parent 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, our indirect Parent 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, our indirect Parent 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, it 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, our indirect Parent 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.

Under the terms of the Second Lien Notes, our indirect Parent 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, it 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.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 6 - Long-Term Debt (Continued)

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 our indirect Parent 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 its 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, our indirect Parent 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, it 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, it 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.

A summary of the loss on the call and tender offers related to our 16% Second Lien Notes and 10% Senior Notes follows (in thousands):

	Year Ended June 30, 2011
16%Second Lien Notes:
Redemption premium paid	$	43,512
Write-off of unamortized premium		(53,134	)
Write-off of unamortized discount		14,618
Write-off of unamortized debt issue costs		410
Total		5,406

10% Senior Notes:
Redemption premium paid		11,152
Write-off of unamortized debt issue costs		5,297
Total		16,449

Total	$	21,855

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 6 - Long-Term Debt (Continued)

Put Premium Financing

We finance puts that we purchase with our hedge providers. Substantially all of our hedges are done with members of our bank groups. Put financing is accounted for as debt and this indebtedness is pari pasu with borrowings under the revolving credit facility. The hedge financing is structured to mature when the put settles so that we realize the value net of hedge financing. As of June 30, 2011 and 2010, our outstanding hedge financing totaled $4.9 million and $2.3 million, respectively.

Interest Expense

For the years ended June 30, 2011, 2010 and 2009, interest expense consisted of the following (in thousands):

	Year Ended June 30,
	2011			2010			2009

Revolving credit facility	$	10,080		$	9,954		$	12,693
9.25% Senior Notes due 2017		37,193			-			-
7.75% Senior Notes due 2019		6,727			-			-
10% Senior Notes due 2013		20,811			45,095			75,000
16% Second Lien Notes due 2014		24,967			34,330			-
Amortization of debt issue cost - Revolving credit facility		6,999			3,015			2,365
Amortization of debt issue cost - 10% Senior Notes due 2013		1,681			2,522			2,856
Amortization of debt issue cost - 16% Second Lien Notes due 2014		54			72			-
Amortization of debt issue cost – 9.25% Senior Notes due 2017		1,196			-			-
Amortization of debt issue cost – 7.25% Senior Notes due 2017		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			-
Put premium financing		819			2,525			1,105
	$	105,673		$	92,838		$	94,019

Bridge Loan Commitment Fee

In November 2010, our indirect Parent 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. It did not utilize the Bridge Facility and paid the banks the $4.5 million commitment fee, which is included in Other Income (Expense).

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 7 - Note Payable

In July 2010, we entered into a note to finance a portion of our insurance premiums. The note was for a total face amount of $19.6 million and bore interest at an annual rate of 2.48%. The note amortized over nine months and there was no remaining balance at June 30, 2011. In May 2011, we entered into a note to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.93%. The note amortizes over ten months.

Note 8 - Asset Retirement Obligations

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

	Year Ended June 30,
	2011			2010

Balance at beginning of year	$	159,277		$	144,199
Liabilities acquired		204,512			68,404
Liabilities incurred		18,086			3,100
Liabilities settled		(73,974	)		(80,044	)
Liabilities sold		(16,626	)		-
Revisions in estimated cash flows		(160	)		131
Accretion expense		32,127			23,487
Total balance at end of year		323,242			159,277
Less: current portion		19,624			35,154
Long-term balance at end of year	$	303,618		$	124,123

Note 9 - Derivative Financial Instruments

We enter into hedging transactions with major financial institutions 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. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a component of operating income, whereas gains and losses from the settlement of hedging contracts are recorded in crude oil and natural gas revenue.

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) plus the difference between the purchased put and the sold put strike price.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 9 - Derivative Financial Instruments (Continued)

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 limits the downside risk of adverse price movements, it also limits future gains from favorable movements.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the year ended June 30, 2011 resulted in a loss in crude oil and natural gas sales in the amount of $20.3 million. For the year ended June 30, 2011, we realized gain of approximately $3.7 million and an unrealized gain of approximately $1.9 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the year ended June 30, 2010 resulted in an increase in crude oil and natural gas sales in the amount of $45.6 million. For the twelve months ended June 30, 2010, we recognized a loss of approximately $1.5 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $11.4 million and an unrealized loss of approximately $5.2 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the year ended June 30, 2009 resulted in an increase in crude oil and natural gas sales in the amount of $42.7 million. For the year ended June 30, 2009, we recognized a gain of approximately $1.5 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $9.9 million and an unrealized loss of approximately $1.3 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

In March 2009, February 2010, September 2010 and October 2010, we monetized certain hedge positions and received cash proceeds of $66.5 million, $5.0 million, $34.1 million and $8.5 million, respectively. These amounts are carried in stockholders’ equity as part of other comprehensive income and will be recognized in income over the contract life of the underlying hedge contracts. Crude oil and natural gas sales were increased by $39.4 million and $43.7 million for years ended June 30, 2011 and 2010, respectively, related to these monetized hedges and, as a result of the future amortization of these hedges, crude oil and natural gas sales will be increased as follows (in thousands):

Quarter Ended
September 30, 2011	$	8,876
December 31, 2011		7,501
March 31, 2012		1,721
June 30, 2012		2,228
Thereafter		3,744
	$	24,070

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 9 - Derivative Financial Instruments (Continued)

As of June 30, 2011, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) in thousands):

	Crude Oil										Natural Gas
	Volume (MBbls)		Contract Price (1)		Total Asset (Liability)			Fair Value Gain (Loss)			Volume (MMMBtus)		Contract Price (1)		Total						Total
Period	Volume (MBbls)		Contract Price (1)		Total Asset (Liability)			Fair Value Gain (Loss)			Volume (MMMBtus)		Contract Price (1)		Asset (Liability)			Fair Value Gain (Loss)			Asset (Liability)			Fair Value Gain (Loss)(2)
Put Spreads
7/11-6/12		564	$	60.00/75.00	$	(2,256	)	$	4,788												$	(2,256	)	$	4,788
7/12-6/13		570		60.00/75.00		45			1,877													45			1,877
						(2,211	)		6,665													(2,211	)		6,665
Puts
7/11-6/12		710		100.38		3,410			(1,616	)												3,410			(1,616	)
Swaps
7/11-6/12		3,662		87.54		(38,676	)		24,962													(38,676	)		24,962
7/12-6/13		2,854		90.38		(29,151	)		18,948													(29,151	)		18,948
7/13-12/13		1,012		94.24		(6,673	)		4,338													(6,673	)		4,338
						(74,500	)		48,248													(74,500	)		48,248
Basis Swaps
8/11-12/11		153		11.75		(383	)		248													(383	)		248
Collars
7/11-6/12		2,967		74.25		(15,607	)		10,145			3,660	$	4.50/5.35	$	554		$	(360	)		(15,053	)		9,785
7/12-6/13		3,141		77.34		(24,768	)		16,099			1,840		4.50/5.35		(63	)		41			(24,831	)		16,140
7/13-12/13		1,472		80.78		(9,794	)		6,366													(9,794	)		6,366
						(50,169	)		32,610							491			(319	)		(49,678	)		32,291
Three-Way Collars
7/11-6/12												8,520	4.09/4.94/5.84			2,714			(1,764	)		2,714			(1,764	)
7/12-6/13												10,950	4.07/4.93/5.87			488			(317	)		488			(317	)
7/13-6/13												5,520	4.07/4.93/5.87			(601	)		391			(601	)		391
																2,601			(1,690	)		2,601			(1,690	)
Total Gain (Loss) on Derivatives					$	(123,853	)	$	86,155						$	3,092		$	(2,009	)	$	(120,761	)	$	84,146

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

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

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 9 - Derivative Financial Instruments (Continued)

The following table quantifies the fair values, on a gross basis, of all our derivative contracts and identifies its balance sheet location as of June 30, 2011 (in thousands):

	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments under Statement 133


Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	6,048	Current	$	58,593
	Non-current		1,248	Non-current		72,719
			7,296			131,312
Derivatives not designated as hedging instruments under Statement 133


Commodity Contracts	Derivative financial instruments			Derivative financial instruments
Current			2,310	Current		3
Non-current			948	Non-current		-
			3,258			3
Total derivatives		$	10,554		$	131,315

The following table quantifies the fair values, on a gross basis, the effect of derivatives on our financial performance and cash flows for the year ended June 30, 2011 (in thousands):

		Location of (Gain) Loss Reclassified from Accumulated OCI into Income (Effective Portion)	Amount of (Gain) Loss Reclassified from OCI into Income (Effective Portion)	Location of (Gain) Loss Recognized in Income on Derivative (Ineffective Portion)	Amount of (Gain) Loss Reclassified from OCI into Income (Ineffective Portion)
Derivatives in Statement 133 Cash Flow Hedging Relationships	Amount of (Gain) Loss Recognized in OCI on Derivative (Effective Portion)



Commodity Contracts	$ 96,190	Revenue	$ 20,311	Gain on derivative financial instruments	$ (21)

Derivatives Not Designated as Hedging Instruments under Statement 133		Amount of (Gain) Loss Recognized in Income on Derivative
	Location of (Gain) Loss Recognized in OCI on Derivative



Commodity Contracts	Gain on derivative financial instruments	$ (5,542)

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 9 - Derivative Financial Instruments (Continued)

We have reviewed the financial strength of our hedge counterparties and believe the credit risk to be minimal. At June 30, 2011, 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.

The following table reconciles the changes in accumulated other comprehensive income (loss) (in thousands):

	Year Ended June 30,
	2011			2010

Balance at beginning of year	$	27,706		$	38,497
Hedging activities:
Commodity
Change in fair value (loss)		(88,768	)		(5,187	)
Unrealized loss recorded in the beginning OCI balance settled and reclassified to income during the fiscal year 2011		(7,422	)		(7,862	)
Interest rate
Change in fair value (loss)		-			2,258
Balance at end of year	$	(68,484	)	$	27,706

The amount reclassified into income during fiscal year 2011 and fiscal year 2010, as shown in the previous schedule in the amount of $(7.4) million and $($7.9) million, is the cumulative unrealized loss that was recorded in the OCI balance as of June 30, 2010 and June 30, 2009, respectively, related to the fiscal year 2011 and fiscal year 2010 contract months. These contract months were settled during the respective accounting period, thus reducing the OCI balance accordingly.

The amount expected to be reclassified to income (loss) in the next 12 months is a loss of $(23.3) million on our commodity hedges.

Note 10 - Supplemental Cash Flow Information

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

	Year Ended June 30,
	2011		2010		2009

Cash paid for interest	$	96,624	$	84,281	$	88,859

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

	Year Ended June 30,
	2011		2010		2009

Put premiums acquired through financing	$	4,267	$	3,928	$	2,598
Additions to property and equipment by recognizingasset retirement obligations		222,438		71,635		4,152
Oil and gas properties contributed by parent		-		273,130		-
Conversion of affiliate debt to equity		-		99,271		-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 11 - Related Party Transactions

During the years ended June 30, 2011, 2010 and 2009, we received capital contributions of $542.1 million, $412.5 million and $65.6 million, respectively, from our Parent.

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, 2011, 2010 and 2009 was approximately $69.6 million, $45.0 million and $20.1 million, respectively, and is included in general and administrative expense.

Note 12 - Hurricanes Gustav and Ike

We have interest in properties that were damaged by Hurricanes Gustav and Ike. Our insurance coverage is an indemnity program that provides for reimbursement after funds are expended. In September 2009, we reached a global settlement for $53.0 million with our insurance carrier. The settlement was incremental to $27.9 million of reimbursements received through June 30, 2009 related to hurricane claims.

Note 13 - 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 financial position or results of operations.

Letters of Credit and Performance Bonds. We had $231.5 million in letters of credit and $26.5 million of performance bonds outstanding as of June 30, 2011.

Drilling Rig Commitments. As of June 30, 2011, we have entered into three drilling rig commitments, one commenced on March 14, 2011 at $110,000 per day for two wells until well completion. Both wells were completed and the rig was released on July 10, 2011. One commenced on May 8, 2011 at $29,600 per day for four wells until well completion. The last one commenced on June 27, 2011 at $85,000 per day until well completion. Since two of the preceding commitments are not finished and extend past June 30, 2011, the commitment amounts cannot be calculated since the well completion dates are not known.

Note 14 - Income Taxes

We are a (U.S.) 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 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 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 ASC 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.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 14 - Income Taxes (Continued)

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

	Year Ended June 30,
	2011			2010		2009

Current	$	93		$	6	$	-
Deferred		(33	)		5,912		(50,006	)
Income tax expense (benefit)	$	60		$	5,918	$	(50,006	)

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

	Year Ended June 30,
	2011			2010			2009

Income (loss) before income taxes	$	85,020		$	42,499		$	(604,213	)
Statutory rate		35	%		35	%		35	%
Income tax expense (benefit) computed at statutory rate		29,757			14,875			(211,474	)
Reconciling items:
State income taxes, net of federal tax benefit		60			4			-
Change in valuation allowance		(23,770	)		(49,562	)		136,346
Revaluation of tax attribute carryovers		(5,989	)		-			-
Cancellation of debt income - GC bond repurchase		-			(12,289	)		12,289
Cancellation of debt income - contributed GC bonds		-			(2,562	)		12,242
Cancellation of debt income - 2nd Lien Notes		-			55,311			-
Other		2			141			591
Income tax expense (benefit)	$	60		$	5,918		$	(50,006	)

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 14 - 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,
	2011		2010
Deferred tax assets:
Asset retirement obligations	$	13,029	$	10,425
Tax loss carryforwards		57,431		91,908
Oil and gas properties		24,318		60,496
Derivative instruments		47,310		-
Deferred state taxes		5,479		-
Other		-		688
Total deferred tax assets		147,567		163,517

Deferred tax liabilities:
Derivative instruments		-		5,868
Deferred state taxes		-		1,100
Retirement of debt		4,184		59,495
Partnership activity		16,468		10,270
Other		12,074		-
Total deferred tax liabilities		32,726		76,733

Valuation allowance		63,014		86,784

Net deferred tax asset	$	51,827	$	-

At June 30, 2011, the U.S. consolidated tax group had a federal tax loss carryforward (“NOLs”) of approximately $191.3 million and a state income tax loss carryforward of approximately $295.0 million, which will expire in various amounts beginning in 2026 and ending in 2029. As of June 30, 2011, Energy XXI Gulf Coast, Inc. was the primary contributor of the federal and state loss carryforwards to the U.S. consolidated tax group.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 14 - 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 3.5% and 4.5% since 2008). 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. As a result of this impairment, for the year ending June 30, 2011, 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 ASC 740. As a result, during the year ended June 30, 2009 we established a valuation allowance of $136.3 million, and adjusted this allowance downward by $73.3 million due principally to the presence of pre-tax income in the subsequent years. This results in an ending valuation allowance of $63.0 million at June 30, 2011. 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 ASC 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 ASC 740-10 or have any gross unrecognized tax benefit. At June 30, 2011, our parent did not have any ASC 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 2010. Tax years ended June 30, 2008 through 2010 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.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 15 - 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 61%, 62% and 65% of our total oil and natural gas revenues during the years ended June 30, 2011, 2010 and 2009, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2011. 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 and or ExxonMobil curtailed their purchases.

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

Derivative Instruments. Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We believe that our credit risk related to the futures and swap contracts is no greater than the risk associated with the primary contracts and that the elimination of price risk through our hedging activities reduces volatility in our reported 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 16 - Fair Value of Financial Instruments

We use various methods to determine the fair values of our financial instruments and other derivatives which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For our natural gas and oil derivatives, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments. Our natural gas and oil derivatives are classified as described below:

Level 2 instruments’ fair values are based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets). Included in this level are our natural gas and oil derivatives whose fair values are based on commodity pricing data obtained from independent pricing sources.

The fair value of our financial instruments at June 30, 2011 was as follow (in thousands):

	Level 2
Assets:
Natural Gas and Oil Derivatives	$	22

Liabilities:
Natural Gas and Oil Derivatives	$	120,783

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 17 - Prepayments and Accrued Liabilities

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

	June 30,
	2011		2010

Prepaid expenses and other current assets
Advances to joint interest partners	$	14,696	$	20,343
Insurance		22,972		266
Inventory		6,305		4,805
Other		497		100
Total prepaid expenses and other current assets	$	44,470	$	25,514

Accrued liabilities
Advances from joint interest partners	$	437	$	3,659
Interest		5,806		3,855
Accrued hedge payable		14,095		9,407
Undistributed oil and gas proceeds		31,880		20,266
Other		871		551
Total accrued liabilities	$	53,089	$	37,738

Note 18 - Subsequent Event

In July 2011, we entered into a note to finance a portion of our insurance premiums. The note is for a total face amount of $6.3 million and bears interest at an annual rate of 1.93%. The note amortizes over the remaining term of the insurance, which matures May 1, 2012.

Note 19 - 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,
	2011		2010		2009
	(In Thousands)
Oil and Gas Activities
Exploration costs	$	98,133	$	51,030	$	121,554
Development costs		180,191		92,949		142,848
Total capital expenditures		278,324		143,979		264,402
Property acquisitions
Proved		722,551		250,795		-
Unproved		289,711		42,242		-
Total acquisitions		1,012,262		293,037		-
Asset retirement obligations, insuranceproceeds and other - net		205,702		17,996		71,788
Total costs incurred	$	1,496,288	$	455,012	$	336,190

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 19 - Supplementary Oil and Gas Information - Unaudited (Continued)

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,
	2011		2010		2009
	(In Thousands)

Unevaluated properties	$	324,549	$	85,211	$	137,489
Wells in progress		142,744		59,099		27,944
	$	467,293	$	144,310	$	165,433

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 United States of America are based on evaluations prepared by third-party reservoir engineers (92% of our proved reserves, at June 30, 2011, on a valuation basis) and, the remainder, internally by EXXI 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.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 19 - 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			Natural Gas			Total
	(MBbls)			(MMcf)			(MBOE)

Proved reserves at June 30, 2008		29,965			129,198			51,498
Production		(4,146	)		(17,472	)		(7,058	)
Extensions and discoveries		971			32,383			6,368
Revisions of previous estimates		4,147			(10,447	)		2,406
Sales of reserves		(64	)		(247	)		(105	)
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

Proved developed reserves
June 30, 2008		19,793			77,991			32,792
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

Proved undeveloped reserves
June 30, 2008		10,172			51,207			18,706
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

Our estimated proved undeveloped (“PUD”) reserves of 35,020 MBOE as of June 30, 2011 increased by 52% over the 23,042 MBOE of PUD reserves estimated at the end of June 30, 2010. During fiscal 2011, we converted 641 MBOE of previously proved undeveloped reserves to proved developed reserves principally through drilling activity in Main Pass 73 and South Timbalier 21 fields.

During fiscal 2011, a total of $38.9 million was spent on projects associated with reserves that were carried as PUD reserves at the end of fiscal year 2010.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 19 - Supplementary Oil and Gas Information - Unaudited (Continued)

We did not have any PUD reserves that were not scheduled to be converted into proved developed reserves within the five year requirement at June 30, 2011. During the year ended June 30, 2011 we reduced our proved reserve estimates by 3.7 MMBOE due to the five year development rule.

	Year Ended June 30,
	2011				2010				2009
	Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)
Commodity prices used in determining future cash flows	$	90.09	$	4.21	$	75.76	$	4.10	$	69.89	$	3.89

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 net cash flows are computed using the average of the first-day-of-the-month commodity prices during the 12-month period ending on June 30, 2011, 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, 2011, 2010 and 2009 are as follows (in thousands):

	June 30,
	2011		2010		2009

Future cash inflows	$	7,989,182	$	4,121,293	$	2,608,640
Less related future
Production costs		2,188,918		1,024,492		688,706
Development and abandonment costs		1,184,728		639,524		522,193
Income taxes		1,073,278		398,399		71,876
Future net cash flows		3,542,258		2,058,878		1,325,865
Ten percent annual discount for estimated timing of cash flows		980,865		509,727		320,589
Standardized measure of discounted future net cash flows	$	2,561,393	$	1,549,151	$	1,005,276

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011 AND 2010

Note 19 - 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,
	2011			2010			2009

Beginning of year	$	1,549,151		$	1,005,276		$	2,509,699
Revisions of previous estimates
Changes in prices and costs		362,283			300,591			(2,200,286	)
Changes in quantities		59,149			27,735			183,783
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs		111,053			27,651			99,024
Purchases of reserves in place		1,553,858			703,456			-
Sales of reserves in place		(171,264	)		-			(5,603	)
Accretion of discount		184,892			105,977			330,143
Sales, net of production costs		(604,057	)		(352,102	)		(306,230	)
Net change in income taxes		(476,319	)		(245,269	)		737,233
Changes in rate of production		(72,069	)		(31,104	)		(240,888	)
Development costs incurred		114,710			108,864			100,847
Other – net		(49,994	)		(101,924	)		(202,446	)
Net change		1,012,242			543,875			(1,504,423	)

End of year	$	2,561,393		$	1,549,151		$	1,005,276

Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - September 1, 2011

Attached files

Energy XXI Ltd Reports