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

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8-K - FORM 8-K - Energy XXI Ltd	form8_k.htm

Exhibit 99.1

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

C O N T E N T S

	Page

Consolidated Balance Sheets	3

Consolidated Statements of Operations	4

Consolidated Statements of Cash Flows	5

Notes to Consolidated Financial Statements	6

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

	March 31,			June 30,
	2011			2010
	(In Thousands)
ASSETS	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	502		$	6,416
Receivables:
Oil and natural gas sales		125,908			68,675
Joint interest billings		5,943			4,388
Insurance and other		2,377			3,168
Prepaid expenses and other current assets		22,857			25,514
Royalty deposit		1,959			2,341
Derivative financial instruments		1,265			19,757
TOTAL CURRENT ASSETS		160,811			130,259

Oil and natural gas properties - full cost method of accounting, including $448.6 million and $144.3 million unevaluated properties at March 31, 2011 and June 30, 2010, respectively, net of accumulated depreciation, depletion and amortization		2,594,970			1,378,222
Other Assets
Derivative financial instruments		2,655			14,610
Deferred taxes		92,777			—
Debt issuance costs, net of accumulated amortization and other assets		36.959			19,637

TOTAL ASSETS	$	2,888,172		$	1,542,728

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	118,545		$	84,802
Accrued liabilities		67,099			37,738
Asset retirement obligations		30,919			35,154
Derivative financial instruments		123,355			1,701
Current maturities of long-term debt		2,539			2,317
TOTAL CURRENT LIABILITIES		342,457			161,712

Long-term debt, less current maturities		1,227,548			771,486
Asset retirement obligations		310,081			124,123
Derivative financial instruments		128, 606			511
TOTAL LIABILITIES		2,008,692			1,057,832

COMMITMENTS AND CONTINGENCIES (NOTE 12)

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		1,442,391			914,467
Accumulated deficit		(418,316	)		(457,278	)
Accumulated other comprehensive income (loss), net of
income tax expense (benefit)		(144,596	)		27,706
TOTAL STOCKHOLDER’S EQUITY		879,480			484,896

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	2,888,172		$	1,542,728

See accompanying Notes to Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2011			2010			2011			2010
	(In Thousands)
Revenues
Oil sales	$	216,711		$	114,095		$	479,080		$	278,438
Natural gas sales		41,925			36,032			97,509			81,102
Total Revenues		258,636			150,127			576,589			359,540

Costs and Expenses
Lease operating expense		70,066			40,832			159,487			101,307
Production taxes		721			870			2,131			3,152
Depreciation, depletion and amortization		90,593			50,104			206,349			129,135
Accretion of asset retirement obligations		9,907			6,335			22,229			17,641
General and administrative expense		22,144			13,746			54,160			34,171
Loss (gain) on derivative financial instruments		(619	)		314			(3,395	)		(4,009	)
Total Costs and Expenses		192,812			112,201			440,961			281,397

Operating Income		65,824			37,926			135,628			78,143

Other Income (Expense)
Bridge loan commitment fees		—			—			(4,500	)		—
Loss on retirement of debt		(12,199	)		—			(17,383	)		—
Other income		2			1			104			26,870
Interest expense		(31,353	)		(21,826	)		(74,887	)		(71,764	)
Total Other Income (Expense)		(43,550	)		(21,825	)		(96,666	)		(44,894	)

Income Before Income Taxes		22,274			16,101			38,962			33,249

Income Taxes		—			1,104			—			13,257

Net Income	$	22,274		$	14,997		$	38,962		$	19,992

See accompanying Notes to Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	March 31,
	2011			2010
	(In Thousands)
Cash Flows from Operating Activities
Net income	$	38,962		$	19,992
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Deferred income tax expense		—			13,252
Change in derivative financial instruments
Proceeds from sale of derivative instruments		42,577			5,000
Other – net		(25,987	)		(25,692	)
Accretion of asset retirement obligations		22,229			17,641
Depreciation, depletion and amortization		206,349			129,135
Payment of interest in-kind		2,225			—
Amortization of deferred gain on debt and debt discount and premium		(43,521	)		(30,851	)
Amortization of debt issuance costs		10,822			6,043
Changes in operating assets and liabilities:
Accounts receivables		(55,544	)		(21,165	)
Prepaid expenses and other current assets		3,039			(12,958	)
Asset retirement obligations		(54,155	)		(58,823	)
Accounts payable and other liabilities		63,106			24,241
Net Cash Provided by Operating Activities		210,102			65,815

Cash Flows from Investing Activities
Acquisitions		(1,022,124	)		(275,364	)
Capital expenditures		(187,798	)		(97,777	)
Insurance payments received		—			53,985
Transfer to restricted cash		—			(2,160	)
Proceeds from the sale of properties		475			—
Net Cash Used in Investing Activities		(1,209,447	)		(321,316	)

Cash Flows from Financing Activities
Proceeds from long-term debt		1,538,526			98,525
Payments on long-term debt		(1,044,851	)		(206,025	)
Contributions from parent		527,924			305,853
Debt issuance costs and other		(28,168	)		(13,002	)
Net Cash Provided by Financing Activities		993,431			185,351

Net Decrease in Cash and Cash Equivalents		(5,914	)		(70,150	)

Cash and Cash Equivalents, beginning of period		6,416			79,620

Cash and Cash Equivalents, end of period	$	502		$	9,470

See accompanying Notes to Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

Note 1 – Basis of Presentation

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”). Parent is a wholly-owned subsidiary of Energy XXI (Bermuda) Limited (“Bermuda”). 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, stockholder’s equity or cash flows.

Interim Financial Statements. The consolidated financial statements for the periods presented herein are unaudited and do not contain all information required by generally accepted accounting principles (“GAAP”) to be included in a full set of financial statements. In the opinion of management, all material adjustments necessary to present fairly the results of operations have been included. All such adjustments are of a normal, recurring nature. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements for the year ended June 30, 2010.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the 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.

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.

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 now 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;

	•	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 –Oil and Gas Properties

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.

Ceiling Test. Under the full cost method of accounting, we are required to perform a “ceiling test” each quarter 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 and future development costs, 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 proceeding twelve-month period and exclude future cash outflows related to estimated abandonment costs. As of the reported balance sheet date, capitalized costs of oil and gas producing properties may not exceed the full cost limitation calculated under the above described rule.

Note 4 – Acquisitions

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 unsecured notes due 2017. The purchase remains subject to certain post-closing adjustments to reflect actual operating results since the effective date of December 1, 2010.

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.

Revenues and expenses related to the ExxonMobil properties for the third quarter ended March 31, 2011 and from the closing date (December 17, 2010) to March 31, 2011 are included in the March 31, 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	$	935,801
Oil and natural gas properties– unevaluated		289,711
Net working capital		101
Asset retirement obligations		(204,512	)
Cash paid	$	1,021,101

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. Significant 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. Significant 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 included in our consolidated statement of operations for the three and nine months ended March 31, 2011 (in thousands).

	Revenue		Earnings (1)

ExxonMobil Acquisition properties from January 1, 2011 through March 31, 2011	$	99,388	$	71,548

ExxonMobil Acquisition properties from December 17, 2010 through March 31, 2011	$	117,395	$	84,915

(1)	Earnings includes revenue less production costs.

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 mirror-image 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 was already operated by us. 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

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. Significant 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. Significant 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.

ExxonMobil and Mit Pro Forma Information

The summarized unaudited pro forma financial information for the nine months ended March 31, 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 the acquisitions as of July 1, 2009 or the results that will be attained in the future (in thousands).

	Revenue		Earnings (1)

Supplemental pro forma for July 1, 2010 through March 31, 2011	$	748,323	$	541,566

Supplemental pro forma for July 1, 2009 through March 31, 2010	$	717,094	$	513,874

(1)	Earnings includes revenue less production costs.

Note 5 – Property and Equipment

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

	March 31, 2011		June 30, 2010
Oil and gas properties
Proved properties	$	3,791,359	$	2,675,308
Less: Accumulated depreciation, depletion and amortization		1,647,744		1,441,396
Proved properties—net		2,143,615		1,233,912
Unproved properties		451,355		144,310
Oil and gas properties—net	$	2,594,970	$	1,378,222

Note 6 – Long-term Debt

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

	March 31, 2011		June 30, 2010

Revolving credit facility	$	119,527	$	109,457
9.25% Senior Notes due 2017		750,000		—
7.75% Senior Notes due 2019		250,000		—
10% Senior Notes due 2013		106,338		276,500
16% Second Lien Notes due 2014 (Exchange Offer)		—		341,319
16% Second Lien Notes due 2014 (Private Placement)		—		44,210
Total 16% Second Lien Notes due 2014		—		385,529
Put premium financing		4,222		2,317
Total debt		1,230,087		773,803
Less current maturities		2,539		2,317
Total long-term debt	$	1,227,548	$	771,486

Maturities of long-term debt as of March 31, 2011 are as follows (in thousands):

Twelve Months Ending March 31,

2012	$	2,539
2013		121,210
2014		106,338
2015		—
2016		—
Thereafter		1,000,000
Total	$	1,230,087

Revolving Credit Facility

This facility, as amended, has a borrowing capacity of $925 million and matures December 31, 2014, provided that in the event that all or any portion of the 10% Senior Notes remain outstanding ninety days prior to June 15, 2013, then such maturity date is March 15, 2013. 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 $700 million. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 2.75% to 3.50% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.50%. 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) our interest rate coverage ratio to be less than 3.0 to 1.0, (3) our secured debt ratio to be more than 2.5 to 1.0, and (4) 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, Bermuda is subject to various other covenants including, but not limited to, those limiting their ability to declare and pay dividends or other payments, their ability to incur debt, changes in control, their 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 March 31, 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 $350 million 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.

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

3)	Allow payments by us to Bermuda 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: (a) the increase of debt incurrence provisions to allow for an incremental unsecured debt basket of up to $1.0 billion, (b) the redetermination of the borrowing base to $700 million, (c) the increase of the notional amount of the revolving credit facility to $925 million, (d) the increase of the letter of credit sublimit to $300 million, and (e) the extension of the maturity date to December 31, 2014, (March 31, 2013 if any of the 10% Senior Notes remain outstanding). 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.

High Yield Facilities

9.25% Senior Notes

On December 17, 2010, we issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Senior Notes”). 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.

The 9.25% Senior Notes are guaranteed by Bermuda and each of our existing and future material domestic subsidiaries. We have the right to redeem the 9.25% Senior Notes under various circumstances and are required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of March 31, 2011 was $806.0 million.

We are obligated to file a registration statement with the SEC to exchange these notes for new freely tradable notes having substantially identical terms within 270 days of the December 17, 2010 issue date and use reasonable efforts to have the registration statement declared effective within that time. Under certain circumstances, we may be required to pay additional cash interest beginning at 0.25% escalating to a maximum of 1% if the registration of the notes does not occur. The registration statement was filed on March 11,2011.

Guarantee of 9.25% Notes

We are the issuer of the 9.25% Notes which are fully and unconditionally guaranteed by Bermuda. Bermuda and its subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from paying dividends to Bermuda except that we may make a one-time payment to them of up to $25 million for the purpose of paying premiums or other payments associated with the early conversion of their 7.25% preferred stock and we may make payments of up to $9 million in any calendar year, subject to certain terms and conditions, so that they may pay dividends on their 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% 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 Bermuda and each of our existing and future material domestic subsidiaries. We have the right to redeem the 7.75% Senior Notes under various circumstances and are required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of March 31, 2011 was $249.7 million.

We are obligated to file a registration statement with the SEC to exchange these notes for new freely tradable notes having substantially identical terms within 270 days of the February 25, 2011 issue date and use reasonable efforts to have the registration statement declared effective within that time. Under certain circumstances, we may be required to pay additional cash interest beginning at 0.25% escalating to a maximum of 1% if the registration of the notes does not occur. The registration statement was filed on March 21, 2011.

Guarantee of 7.75% Notes

We are the issuer of the 7.75% Notes which are fully and unconditionally guaranteed by Bermuda. Bermuda and its subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from paying dividends to Bermuda except that we may make a one-time payment to Bermuda of up to $25 million for the purpose of paying premiums or other payments associated with the early conversion of their 7.25% preferred stock and we may make payments of up to $9 million in any calendar year, subject to certain terms and conditions, so that they may pay dividends on their outstanding preferred stock.

10% Senior Notes

On June 8, 2007, Bermuda completed a private offering of $750 million aggregate principal amount of our 10% Senior Notes due 2013 (the “Old 10% Notes”). On October 16, 2007, we 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. We did not receive any cash proceeds from the exchange of the Old 10% Notes for the New Senior Notes.

The New 10% Notes are guaranteed by Bermuda and each of our existing and future material domestic subsidiaries. We have the right to redeem the New 10% Notes under various circumstances and are required to make an offer to repurchase the New 10% 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 New 10% Notes.

Bermuda previously purchased a total of $126.0 million aggregate principal amount of the New 10% Notes at a cost of $90.9 million, plus accrued interest of $3.3 million for a total cost of $94.2 million, reflecting a total gain of $35.1 million pre-tax. As discussed below, on November 12, 2009, we 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, Bermuda contributed $126 million face value of New 10% Notes which they had previously purchased to us, and we subsequently retired them.

On December 17, 2010, we 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, we 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, we called the remaining $106.3 million of our New 10% Notes. The call price is 102.5% of par and is expected to close on June 15, 2011.

We believe that the fair value of the $106.3 million of New 10% Notes outstanding as of March 31, 2011 was $110.9 million.

Guarantee of New 10% Notes

We are the issuer of the New 10% Notes which are fully and unconditionally guaranteed by Bermuda. Bermuda and our subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from paying dividends to Bermuda except that we may make a one-time payment to them of up to $25 million for the purpose of paying premiums or other payments associated with the early conversion of their 7.25% preferred stock and we may make payments of up to $9 million in any calendar year, subject to certain terms and conditions, so that they may pay dividends on their outstanding preferred stock.

16% Second Lien Notes

On November 12, 2009, we 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 Bermuda’s common stock).

The Second Lien Notes have a maturity date of June 2014 and are secured by a second lien in our oil and gas properties. In addition, the Second Lien Notes are 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 is paid through the issuance of additional Second Lien Notes on each interest payment date. These additional Second Lien Notes issued as Second Lien Note PIK interest are identical in terms and conditions to the original Second Lien Notes.

Under the terms of the Second Lien Notes, we were 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 have identical terms and conditions as the Second Lien Notes. On April 5, 2010, we commenced an offer to exchange the Second Lien Notes for Registered Second Lien Notes. The exchange offer expired on May 3, 2010 and closing was on May 6, 2010. The tendered bonds represented 99.96% of the bonds outstanding.

For accounting purposes, the $278 million aggregate principal amount of Second Lien Notes exchanged for $347.5 million aggregate principal amount of New Senior Notes were recorded at the carrying value of the Registered Second Lien Notes ($347.5 million) and the $69.5 million difference between face value of the Second Lien Notes and carrying value of the New Senior Notes will be 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 we 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 closing price of $10.60 per share of our 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 will be 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, we called for redemption of $119.7 million aggregate principal amount of our 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, we commenced a tender offer (the “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, we commenced a call of the remaining outstanding 16% Second Lien Notes which closed on January 18, 2011. In December 2010, we 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):

	Three Months Ended			Nine Months Ended
	March 31, 2011			March 31, 2011
16%Second Lien Notes:
Redemption premium paid	$	598		$	43,512
Write-off of unamortized premium		(537	)		(53,134	)
Write-off of unamortized discount		157			14,618
Write-off of unamortized debt issue costs		4			410
Total		222			5,406

10% Senior Notes:
Redemption premium paid		8,493			8,493
Write-off of unamortized debt issue costs		3,484			3,484
Total		11,977			11,977

Total	$	12,199		$	17,383

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 March 31, 2011 and June 30, 2010, our outstanding hedge financing totaled $4.2 million and $2.3 million, respectively.

Interest Expense

For the three months and nine months ended March 31, 2011 and 2010, interest expense consisted of the following (in thousands):

	Three Months Ended					Nine Months Ended
	March 31,					March 31,
	2011		2010			2011			2010

Revolving credit facility	$	4,243	$	2,432		$	7,140		$	8,541
9.25% Senior Notes due 2017		17,344		—			19,849			—
7.75% Senior Notes due 2019		1,776		—			1,776			—
10% Senior Notes due 2013		4,770		6,818			18,595			38,140
16% Second Lien Notes due 2014		—		13,521			24,967			20,732
Amortization of debt issue cost - Revolving credit facility		2,174		965			4,699			1,869
Amortization of debt issue cost - 10% Senior Notes due 2013		314		589			1,492			1,933
Amortization of debt issue cost - 16% Second Lien Notes due 2014		—		29			54			43
Amortization of debt issue cost – 9.25% Senior Notes due 2017		552		—			644			—
Amortization of debt issue cost – 7.25% Senior Notes due 2017		45		—			45			—
Discount amortization - 16% Second Lien Notes due 2014 (Exchange Offer)		—		1,042			1,894			1,563
Premium amortization - 16% Second Lien Notes due 2014 (Private Placement)		—		(3,791	)		(6,889	)		(5,686	)
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 and other		135		221			621			2,432
	$	31,353	$	21,826		$	74,887		$	71,764

Bridge Loan Commitment Fee

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

Note 7 – Note Payable

In July 2010, we entered into a note to finance a portion of our insurance premiums. The note is for a total face amount of $19.6 million and bears interest at an annual rate of 2.48%. The note amortized over nine months and there is no remaining balance at March 31, 2011.

Note 8 – Asset Retirement Obligations

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


Balance at June 30, 2010	$	159,277
Liabilities acquired		204,512
Liabilities incurred		9,137
Liabilities settled		(54,155	)
Accretion expense		22,229
Total balance at March 31, 2011		341,000
Less current portion		30,919
Long-term balance at March 31, 2011	$	310,081

As discussed in Note 4, the asset retirement obligations acquired essentially relate to the ExxonMobil Acquisition and is a provisional estimate.

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, 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.

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 three months ended March 31, 2011 resulted in a decrease in crude oil and natural gas sales in the amount of $6.6 million. For the three months ended March 31, 2011, we recognized a gain of approximately $0.2 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and an unrealized gain of approximately $0.4 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 three months ended March 31, 2010 resulted in an increase in crude oil and natural gas sales in the amount of $9.3 million. For the three months ended March 31, 2010, we recognized a loss of approximately $0.9 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $0.3 million and an unrealized gain of approximately $0.3 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 nine months ended March 31, 2011 resulted in a loss in crude oil and natural gas sales in the amount of $1.0 million. For the nine months ended March 31, 2011, we recognized a loss of approximately $0.1 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $3.2 million and an unrealized gain of approximately $0.3 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 nine months ended March 31, 2010 resulted in an increase in crude oil and natural gas sales in the amount of $40.1 million. For the nine months ended March 31, 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 $10.4 million and an unrealized loss of approximately $4.9 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 $9.2 million and $10.4 million for three months ended March 31, 2011 and 2010, respectively, and were increased by $30.0 million and $33.4 million for nine months ended March 31, 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
June 30, 2011	$	9,352
September 30, 2011		8,875
December 31, 2011		7,501
March 31, 2012		1,721
Thereafter		5,973
	$	33,422

As of March 31, 2011, we had the following contracts outstanding (Asset (Loss) and Fair Value Gain (Loss) in thousands):

	Crude Oil				Natural Gas
	Volume (MBbls)	Contract Price (1)	Total		Volume (MMMBtus)	Contract Price (1)	Total		Total
Period	Volume (MBbls)	Contract Price (1)	Liability	Fair Value Gain	Volume (MMMBtus)	Contract Price (1)	Asset (Liability)	Fair Value Gain (Loss)	Asset (Liability)	Fair Value Gain (Loss)(2)

Put Spreads
4/11-3/12	1,271	$60.00/$75.00	$(3,781)	$ 5,561					$(3,781)	$5,561
4/12-3/13	853	60.00/75.00	(583)	2,464					(583)	2,464
			(4,364)	8,025					(4,364)	8,025

Puts
4/11-3/12	137	71.67	(15)	298					(15)	298

Swaps
4/11-3/12	3,919	86.24	(84,252)	54,498			$459	$(395)	(83,793)	54,103
4/12-3/13	3,273	89.21	(52,760)	34,294					(52,760)	34,294
4/13-12/13	2,008	94.24	(12,937)	8,409					(12,937)	8,409
			(149,949)	97,201			459	(395)	(149,490)	96,806
Collars
4/11-3/12	2,952	73.85/99.16	(35,835)	23,293	3,660	$4.50/$5.35	280	(183)	(35,555)	23,110
4/12-3/13	3,250	75.82/102.26	(39,011)	25,357	2,750	4.50/5.35	(395)	256	(39,406)	25,613
4/13-12/13	2,920	80.78/106.79	(17,959)	11,673					(17,959)	11,673
			(92,805)	60,323			(115)	73	(92,920)	60,396
Three-Way Collars
4/11-3/12					5,180	3.91/4.94/5.72	1,066	(693)	1,066	(693)
4/12-3/13					7,300	4.10/4.90/5.78	(725)	471	(725)	471
4/13-12/13					7,300	4.10/4.90/5.78	(1,593)	1,035	(1,593)	1,035
							(1,252)	813	(1,252)	813

Total Gain (Loss) on Derivatives			$ (247,133)	$165,847			$(908)	$491	$(248,041)	$166,338

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

(2) The gain (loss) on derivative contracts is net of applicable income taxes and includes only those contracts that have been designated as hedges.

The following table quantifies the fair values, on a gross basis, of all our derivative contracts and identifies its balance sheet location as of March 31, 2011 (in thousands):

	Asset Derivatives		Liability Derivatives
	Balance Sheet Location	Fair Value	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Commodity Contracts	Derivative financial instruments		Derivative financial instruments
	Current	$2,080	Current	$124,665
	Non-current	1,689	Non-current	127,640
		3,769		252,305
Derivatives not designated as hedging instruments
Commodity Contracts	Derivative financial instruments		Derivative financial instruments
	Current	496	Current	1
Total derivatives		$4,265		$252,306

The following table quantifies the fair values, on a gross basis, the effect of derivatives on our financial performance and cash flows for the nine months ended March 31, 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 Cash Flow Hedging Relationships	Amount of (Gain) Loss Recognized in Income on Derivative (Effective Portion)



Commodity Contracts	$172,301	Revenue	$966	(Gain) /Loss on derivative financial instruments	$58

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



Commodity Contracts	(Gain) loss on derivative financial instruments	$(3,453)

We have reviewed the financial strength of our hedge counterparties and believe the credit risk to be minimal. At March 31, 2011, we had no deposits for collateral with our counterparties.

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

Accumulated other comprehensive income – June 30, 2010	$	27,706
Hedging activities:
Commodity
Change in fair value loss		(168,973	)
Reclassified to income		(3,329	)
Accumulated other comprehensive loss –March 31, 2011	$	(144,596	)

The amounts expected to be reclassified to income in the next twelve months are $7.2 million income on our commodity hedges.

Note 10 – 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, indirectly owns 100% of U.S. Parent, but is not a member of the U.S. 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. ASC 740 (formerly FAS 109) provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated financial reporting group should be based upon a reasonable allocation of the income tax amounts of that group. As such, the income tax amounts presented herein have been presented by applying the provisions of ASC 740 to us in this manner.

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, as of December 31, 2010, we are in a position of cumulative reporting losses for the preceding reporting periods. The volatility of energy prices has been problematic and not readily determinable by our management. Under these current circumstances, it is management’s opinion that the realization of our tax attributes beyond expected current-year taxable income (including the reversal of existing taxable temporary differences) does not reach the “more likely than not” criteria under ASC 740. Accordingly, during the year ended June 30, 2009, we established a valuation allowance of $175.0 million, and have subsequently reduced the valuation allowance due to anticipated pre-tax earnings in the present fiscal year.

Note 11 - Related Party Transactions

During the nine months ended March 31, 2011 and 2010, our Parent contributed capital of $527.9 million and $405.1 million, respectively, to us.

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 three months and nine months ended March 31, 2011 and 2010 was approximately $22.2 million, $13.6 million, $54.1 million and $33.6 million, respectively, and is included in general and administrative expense.

Note 12 — 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 affect on our financial position or results of operations.

Letters of Credit and Performance Bonds. We had $231.5 million in letters of credit and $26.6 million of performance bonds outstanding as of March 31, 2011.

Drilling Rig Commitments. We entered into a drilling rig commitment for two wells on March 14, 2011 at $110,000 per day until well completion. The commitment extends past March 31, 2011, thus, the commitment amount cannot be calculated since the well completion date is not known.

Note 13 — 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 March 31, 2011 was as follow (in thousands):

	Level 2
Assets:
Natural Gas and Oil Derivatives	$	3,920

Liabilities:
Natural Gas and Oil Derivatives	$	251,961

Note 14 — Prepaid Expenses and Other Current Assets and Accrued Liabilities

Prepaid expenses and other current assets and accrued liabilities consist of the following (in thousands):

	March 31, 2011		June 30, 2010

Prepaid expenses and other current assets
Advances to joint interest partners	$	8,887	$	20,343
Insurance		7,372		266
Inventory		6,177		4,805
Other		421		100
Total prepaid expenses and other current assets	$	22,857	$	25,514

Accrued liabilities
Advances from joint interest partners	$	262	$	3,659
Interest		24,788		3,855
Accrued hedge payable		18,163		9,407
Undistributed oil and gas proceeds		23,353		20,266
Other		533		551
Total accrued liabilities	$	67,099	$	37,738

Note 15 – Supplemental Cash Flow Information

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

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2011		2010		2011		2010

Cash paid for interest	$	7,662	$	3,014	$	49,938	$	44,459

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

	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2011			2010			2011		2010

Additions to property and equipment by recognizing asset retirement obligations	$	6,483		$	62,232		$	213,650	$	63,915
Financing of insurance premiums		(6,574	)		(6,549	)		—		—

Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - May 2, 2011

Attached files

Energy XXI Ltd Reports