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

SEPTEMBER 30, 2013

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2013

C O N T E N T S

	Page

Consolidated Balance Sheets	3

Consolidated Statements of Income	4

Consolidated Statements of Comprehensive Income (Loss)	5

Consolidated Statements of Cash Flows	6

Notes to Consolidated Financial Statements	7

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	September 30,		June 30,
	2013		2013
	(Unaudited)
ASSETS
CURRENT ASSETS
Receivables:
Oil and natural gas sales	$	139,226	$	132,521
Joint interest billings		10,362		9,505
Insurance and other		6,711		5,367
Prepaid expenses and other current assets		51,977		47,864
Derivative financial instruments		17,202		38,389
TOTAL CURRENT ASSETS		225,478		233,646

Oil and gas properties-net – full cost method of accounting, including $435.2 million and $422.6 million of unevaluated properties not being amortized at September 30, 2013 and June 30, 2013, respectively		3,399,831		3,289,505
Other Assets
Note receivable from Energy XXI, Inc.		68,416		67,935
Derivative financial instruments		9,667		21,926
Debt issuance costs, net of accumulated amortization		32,067		24,791

TOTAL ASSETS	$	3,735,459	$	3,637,803

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	186,709	$	219,822
Accrued liabilities		63,383		58,334
Note payable		18,031		22,349
Asset retirement obligations		27,702		29,500
Derivative financial instruments		69		40
Current maturities of long-term debt		15,471		18,838
TOTAL CURRENT LIABILITIES		311,365		348,883

Long-term debt, less current maturities		1,524,619		1,344,843
Deferred taxes		168,996		153,805
Asset retirement obligations		263,530		258,318
Other liabilities		1,429		—
TOTAL LIABILITIES		2,269,939		2,105,849

COMMITMENTS AND CONTINGENCIES (NOTE 11)

STOCKHOLDER’S EQUITY
Common stock, $0.01 par value, 1,000,000 shares
authorized and 100,000 shares issued and outstanding		1		1
Additional paid-in capital		1,413,704		1,426,349
Retained earnings		45,018		79,304
Accumulated other comprehensive income, net of
income taxes		6,797		26,300
TOTAL STOCKHOLDER’S EQUITY		1,465,520		1,531,954

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	3,735,459	$	3,637,803

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands)

(Unaudited)

	Three Months Ended
	September 30,
	2013			2012

Revenues
Oil sales	$	289,229		$	247,330
Natural gas sales		35,363			22,897
Total Revenues		324,592			270,227

Costs and Expenses
Lease operating expense		85,763			82,481
Production taxes		1,398			1,247
Gathering and transportation		5,345			7,991
Depreciation, depletion and amortization		99,462			83,970
Accretion of asset retirement obligation		7,326			7,652
General and administrative expense		21,329			22,093
(Gain) loss on derivative financial instruments		1,441			5,618
Total Costs and Expenses		222,064			211,052

Operating Income		102,528			59,175

Other Income (Expense)
Interest income		483			457
Interest expense		(29,604	)		(26,518	)
Total Other Expense		(29,121	)		(26,061	)

Income Before Income Taxes		73,407			33,114

Income Tax Expense		25,693			11,765

Net Income	$	47,714		$	21,349

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)

	Three Months September 30,
	2013			2012

Net Income	$	47,714		$	21,349

Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		(22,656	)		(37,740	)
Effective portion reclassified to earnings during the period		(7,348	)		(10,540	)
Total Other Comprehensive Income (Loss)		(30,004	)		(48,280	)
Income Tax Benefit		10,501			16,898
Net Other Comprehensive Income (Loss)		(19,503	)		(31,382	)

Comprehensive Income (Loss)	$	28,211		$	(10,033	)

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Three Months Ended
	September 30,
	2013			2012

Cash Flows from Operating Activities
Net income	$	47,714		$	21,349
Adjustments to reconcile net income to net cash provided by (used in)
operating activities:
Depreciation, depletion and amortization		99,462			83,970
Deferred income tax expense		25,693			11,765
Change in derivative financial instruments
Proceeds from sale of derivative instruments		—			61
Other – net		(2,356	)		(5,283	)
Accretion of asset retirement obligations		7,326			7,652
Amortization and write-off of debt issuance costs		1,455			1,891
Changes in operating assets and liabilities:
Accounts receivables		(2,238	)		10,694
Prepaid expenses and other current assets		(8,431	)		(711	)
Asset retirement obligations		(18,063	)		(10,136	)
Accounts payable and other liabilities		(26,634	)		16,333
Net Cash Provided by Operating Activities		123,928			137,585

Cash Flows from Investing Activities
Acquisitions		(15	)		—
Capital expenditures		(197,369	)		(178,672	)
Proceeds from the sale of properties		1,748			—
Property deposit		—			(3,500	)
Other		—			(6	)
Net Cash Used in Investing Activities		(195,636	)		(182,178	)

Cash Flows from Financing Activities
Proceeds from long-term debt		1,040,697			218,322
Payments on long-term debt		(865,128	)		(186,813	)
Dividends to parent		(82,000	)		—
Return to parent		(13,126	)		(32,300	)
Debt issuance costs		(8,731	)		—
Other		(4	)		(10	)
Net Cash Provided by (Used in) Financing Activities		71,708			(801	)

Net Increase (Decrease) in Cash and Cash Equivalents		—			(45,394	)

Cash and Cash Equivalents, beginning of period		—			45,394

Cash and Cash Equivalents, end of period	$	—		$	—

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2012

(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”). Energy XXI (Bermuda) Limited (“Bermuda”), indirectly owns 100% of Parent. 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 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 accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended June 30, 2013.

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

Note 2 – Recent Accounting Pronouncements

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

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

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

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

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

Note 3 – Acquisitions and Dispositions

ExxonMobil oil and gas properties interests acquisition

On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“Exxon”) for a total cash consideration of approximately $32.8 million. The GOM Interests cover 5,000 gross acres on Vermilion Block 164 (“VR 164”). We are the operator of these properties. In addition to acquiring the GOM Interests, we entered into a joint venture agreement with Exxon to explore for oil and gas on nine contiguous blocks adjacent to VR 164 in shallow waters on the GOM shelf. We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012.

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

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

Dynamic Offshore oil and gas properties interests acquisition

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

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

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

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McMoRan oil and gas properties interests acquisition

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

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

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

RoDa oil and gas properties interests acquisition

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

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

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

Tammany oil and gas properties interests acquisition

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

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

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

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

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Apache Joint Venture

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

The area of mutual interest under this Exploration Agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million of which approximately $27.5 million was incurred through September 30, 2013. We have presently consented to participate in drilling one well and have an option to participate in two other wells under the current drilling program. Drilling on the first well commenced in May 2013 and our share of the costs related to this well at September 30, 2013 were approximately $11.7 million.

As of September 30, 2013, we paid consideration of approximately $3.5 million, being our participation interest, to Apache for 21 non-producing primary-term leases.

Note 4 – Property and Equipment

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

	September 30,		June 30,
	2013		2013
Oil and gas properties
Proved properties	$	5,532,851	$	5,335,737
Less: accumulated depreciation, depletion, amortization and impairment		2,568,244		2,468,783
Proved properties		2,964,607		2,866,954
Unevaluated properties		435,224		422,551
Oil and gas properties-net	$	3,399,831	$	3,289,505

The Company’s investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions and wells in progress. Costs associated with unproved properties are transferred to evaluated properties upon the earlier of 1) when a determination is made whether there are any proved reserves related to the properties, or 2) amortized over a period of time of not more than four years.

Further, unevaluated properties include $353.1 million in wells in progress primarily related to our participation with Freeport-McMoRan Oil & Gas LLC (Freeport McMoRan) and Chevron U.S.A. Inc. who operate several prospects in the ultra-deep shelf and onshore area (“ultra-deep trend”) in the Gulf of Mexico and to the joint ventures with Exxon Mobil Corporation and Apache Corporation to jointly participate in exploration of oil and gas on the Gulf of Mexico Shelf. Activities related to certain of these well operations are controlled by the operator and also these wells may have continued drilling and completion activities or, may require development of specialized equipment necessary to complete and test these wells for production.

As of September 30, 2013, the costs associated with our wells in progress and their status was as follows (in millions):

Project Name	Cost		Status

Davy Jones No. 1	$	108.9	Work ongoing to establish commercial production.
Davy Jones Offset Appraisal Well		45.1	Operations to commence completion expected during the calendar year 2014.
Blackbeard West		57.1	Completion using conventional technologies planned during second quarter of calendar year 2014.
Blackbeard East		50.7	Plans to begin development of the shallow zones in late calendar year 2014.
Merlin		37.5	Presently drilling at 14,115' to an estimated drilling measured depth of 19,700'.
Lomond North		26.3	Coring complete, coring analysis and drilling in progress.
Other		27.5
Total	$	353.1

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Note 5 – Long-Term Debt

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

	September 30,		June 30,
	2013		2013

Revolving credit facility	$	21,000	$	339,000
9.25% Senior Notes due 2017		750,000		750,000
7.75% Senior Notes due 2019		250,000		250,000
7.50% Senior Notes due 2021		500,000		—
Derivative instruments premium financing		19,090		24,681
Total debt		1,540,090		1,363,681
Less current maturities		15,471		18,838
Total long-term debt	$	1,524,619	$	1,344,843

Maturities of long-term debt as of September 30, 2013 are as follows (in thousands):

Twelve Months Ended September 30,

2014	$	15,471
2015		3,619
2016		—
2017		—
2018		771,000
Thereafter		750,000
Total	$	1,540,090

Revolving Credit Facility

We entered into the second amended and restated first lien credit agreement (“First Lien Credit Agreement”) in May 2011. This facility, as amended, has lender commitments of $1,700 million and matures on April 9, 2018. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, we are allowed to pay Bermuda a limited amount of distributions, subject to certain terms and conditions.

On October 4, 2011, we entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement, which provided us the ability to make distributions to Bermuda for various purposes, subject to varying limitations depending on the purpose of the distribution. Our ability to make dividends was subject to our meeting minimum liquidity and maximum revolver utilization thresholds, and were further limited to an aggregate cumulative amount equal to $70 million plus 50% of our cumulative Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter. Our ability to make dividend payments to us was modified in subsequent amendments.

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

On October 19, 2012, we entered into the Third Amendment (the “Third Amendment”) to the First Lien Credit Agreement. The Third Amendment provides changes, supplements, and other modifications for information specific to the lenders under the First Lien Credit Agreement and increased the borrowing base to $825 million.

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On April 9, 2013, we entered into the Fourth Amendment (the “Fourth Amendment”) to the First Lien Credit Agreement. The Fourth Amendment included the following revisions: (a) extension of the maturity date to April 9, 2018, (b) increase of commitments under the First Lien Credit Agreement from $925 million to $1,700 million, (c) increase in the borrowing base to $850 million, (d) reduction of the ranges of applicable margins on all borrowing by 0.25% to 0.50%, (e) approval of an increase in the cash distribution basket under which Bermuda can make dividend payments on its preferred and common stock, from $17 million to $50 million per calendar year, (f) increase in the general basket of permitted unsecured indebtedness from $250 million to $750 million, subject to a reduction in the borrowing base of 25 percent of any unsecured indebtedness issued in excess of $250 million, and (g) approval of additional ability of an affiliated entity to reinsure our assets and operations and of our subsidiaries.

On May 1, 2013, we entered into the Fifth Amendment (the “Fifth Amendment”) to the First Lien Credit Agreement. The Fifth Amendment provides changes and other modifications to the First Lien Credit Agreement to increase our ability to make dividends and other distributions to Bermuda. Under the Amendment, we are permitted to make dividends and other distributions in an amount of up to $350 million per calendar year to the extent that, following each distribution, we and our subsidiaries have liquidity, in the form of cash and available borrowing capacity under the First Lien Credit Agreement, of the greater of $150 million or 15% of the borrowing base under the First Lien Credit Agreement. Further, the amendment limits the total aggregate distributions made by us to a maximum of $70 million plus 50% of our cumulative consolidated net income between October 1, 2010 and the most recently ended fiscal quarter, and requires that the making of any such dividend or other distributions must otherwise comply with all contractual restrictions and obligations applicable to us.

On September 27, 2013, we entered into the Sixth Amendment (the “Sixth Amendment”) to Second Amended and Restated First Lien Credit Agreement. Under the Sixth Amendment, our borrowing base was established at $1,087.5 million (an increase from $850 million) until the next redetermination of such borrowing base pursuant to the terms of the First Lien Credit Agreement. Additionally, the Amendment generally provides changes and other modifications to the First Lien Credit Agreement to permit us to specify interest periods for LIBOR loans of less than a month (so that we are able to have new borrowings continued under interest periods with already outstanding loans) and makes some related adjustments to the definition of LIBOR and other technical corrections.

The First Lien Credit Agreement, as amended, requires us to maintain certain financial covenants. Specifically, we may not permit the following under First Lien Credit Agreement: (a) our total leverage ratio to be more than 3.5 to 1.0, (b) our interest coverage ratio to be less than 3.0 to 1.0, and (c) our current ratio (in each case as defined in our First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, it is subject to various other covenants including, but not limited to, those limiting our ability to declare and pay dividends or other payments, the ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

As of September 30, 2013, we were in compliance with all covenants under the First Lien Credit Agreement.

High Yield Notes

9.25% Senior Notes due 2017

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

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

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

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of September 30, 2013 was $834.8 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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7.75% Senior Notes Due 2019

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

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

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

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of September 30, 2013 was $263.3 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

7.50% Senior Notes Due 2021

On September 26, 2013, we issued $500 million face value of 7.50%, unsecured senior notes due December 15, 2021 at par (“7.50% Senior Notes”). Presently, the 7.50% Senior Notes are not registered under the Securities Act, however we and our guarantors will agree, pursuant to a registration rights agreement with the initial purchasers of the 7.50 % Senior Notes, to file a registration statement with the Securities and Exchange Commission (“SEC”) with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 7.50% Senior Notes and use our reasonable best efforts to cause that registration statement to be declared effective within 270 days after the issue date of the 7.50% Senior Notes. We incurred underwriting and direct offering costs of $7.5 million which have been capitalized and will be amortized over the life of the 7.50% Senior Notes.

On or after December 15, 2016, we will have the right to redeem all or some of the 7.50% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, we may redeem up to 35% of the aggregate principal amount of the 7.50% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, we may redeem all or part of the 7.50% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. We are required to make an offer to repurchase the 7.50% Senior Notes upon a change of control and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 7.50% Senior Notes.

The indenture governing the 7.50% Senior Notes will, among other things, limit our ability and the ability of Bermuda’s restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of Bermuda’s assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

We believe that the fair value of the $500 million of 7.50% Senior Notes outstanding as of September 30, 2013 was $497.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

Guarantee of Securities Issued by Us

We are the issuer of each of the 9.25% Senior Notes, 7.75% Senior Notes and 7.50% Senior Notes, which are fully and unconditionally guaranteed by Bermuda and each of our existing and future material domestic subsidiaries. Bermuda and its subsidiaries, other than us, have no significant independent assets or operations. We are permitted to make dividends and other distributions subject to certain limitations as more fully disclosed in this note above under the caption “Revolving Credit Facility”.

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Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value net of derivative instrument premium financing. As of September 30, 2013 and June 30, 2013, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $19.1 million and $24.7 million, respectively.

Interest Expense

For the three months ended September 30, 2013 and 2012, interest expense consisted of the following (in thousands):

	Three Months Ended September 30,
	2013		2012

Revolving credit facility	$	5,219	$	2,179
9.25% Senior Notes due 2017		17,344		17,344
7.75% Senior Notes due 2019		4,844		4,844
7.50% Senior Notes due 2021		521		—
Amortization of debt issue cost - Revolving credit facility		806		1,242
Amortization of debt issue cost – 9.25% Senior Notes due 2017		552		552
Amortization of debt issue cost – 7.75% Senior Notes due 2019		97		97
Derivative instruments financing and other		221		260
	$	29,604	$	26,518

Note 6 – Notes Payable

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

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

In May 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $24.8 million and bears interest at an annual rate of 1.623%. The note amortizes over the remaining term of the insurance, which matures April 26, 2014. The balance outstanding as of September 30, 2013 was $15.7 million.

In July 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our Weather Based Insurance Linked Securities premiums. The note was for a total face amount of $2.9 million and bears interest at an annual rate of 1.823%. The note amortizes over the remaining term of the insurance, which matures June 1, 2014. The balance outstanding as of September 30, 2013 was $2.4 million.

Note 7 – Asset Retirement Obligations

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

Balance at June 30, 2013	$	287,818
Liabilities incurred		14,151
Liabilities settled		(18,063	)
Accretion expense		7,326
Total balance at September 30, 2013		291,232
Less current portion		27,702
Long-term balance at September 30, 2013	$	263,530

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Note 8 – Derivative Financial Instruments

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

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

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

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

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

We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended September 30, 2013, and received $181.3 million. These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts. As of September 30, 2013, we had $4.5 million of monetized amounts remaining in OCI which will be recognized during the quarter ending December 31, 2013.

During the quarter ended March 31, 2013, we repositioned certain hedge positions by selling puts on certain existing calendar year 2013 hedge collar contracts and purchasing new put spread contracts. The $2.2 million received from the sale of puts were recorded as deferred hedge revenue and will be recognized in income over the life of the underlying hedge contracts through December 31, 2013. As of September 30, 2013, we had $0.7 million in deferred hedge revenue which will be recognized during the quarter ending December 31, 2013.

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As of September 30, 2013, we had the following net open crude oil derivative positions:

								Weighted Average Contract Price
								Swaps		Collars/Put Spreads
Period	Type of Contract	Index	Volumes (MBbls)					Fixed Price		Sub Floor		Floor		Ceiling

October 2013 - December 2013	Three-Way Collars	Oil-Brent-IPE		1,012		(1	)			$	85.91	$	105.91	$	125.88
October 2013 - December 2013	Put Spreads	Oil-Brent-IPE		460							87.00		106.00
October 2013 - December 2013	Three-Way Collars	NYMEX-WTI		460							70.00		90.00		136.32
October 2013 - December 2013	Collars	NYMEX-WTI		322									73.57		105.63
October 2013 - December 2013	Swaps	NYMEX-WTI		46				$	86.60
October 2013 - December 2013	Swaps	NYMEX-WTI		(46	)				88.20
January 2014 - December 2014	Three-Way Collars	Oil-Brent-IPE		2,373							68.08		88.08		130.88
January 2014 - December 2014	Collars	Oil-Brent-IPE		730									90.00		108.38
January 2014 - December 2014	Three-Way Collars	NYMEX-WTI		3,650							70.00		90.00		137.14
January 2015 - December 2015	Three-Way Collars	Oil-Brent-IPE		2,190							71.67		91.67		111.88

(1) The Oil-Brent-IPE three-way collars for the period from October 2013 through December 2013 include the repositioned derivative contracts referred to above. The newly purchased put spreads have been designated as hedges whereas the call option remaining from the collar after the put was sold no longer qualifies for hedge accounting. However, the combination of the put spread and call contracts effectively result into a three-way collar.

As of September 30, 2013, we had the following net open natural gas derivative positions:

					Weighted Average Contract Price
					Collars/Put Spreads
Period	Type of Contract	Index	Volumes (MMBtu)		Sub Floor		Floor		Ceiling

October 2013 - December 2013	Three-Way Collars	NYMEX-HH		4,900	$	3.62	$	4.41	$	5.22
October 2013 - December 2013	Put Spreads	NYMEX-HH		620		4.00		4.90
January 2014 – December 2014	Three-Way Collars	NYMEX-HH		10,950		3.25		4.00		4.74

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

	Asset Derivative Instruments						Liability Derivative Instruments
	September 30, 2013			June 30, 2013			September 30, 2013			June 30, 2013
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Derivative Instruments designated as hedging instruments:
Derivative financial instruments	Current	$	30,642	Current	$	52,216	Current	$	13,873	Current	$	14,609
	Non-Current		24,870	Non-Current		42,263	Non-Current		15,203	Non-Current		20,337
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments	Current		978	Current		1,976	Current		614	Current		1,234
	Non-Current		—	Non-Current		—	Non-Current		—	Non-Current		—
Total		$	56,490		$	96,455		$	29,690		$	36,180

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

	Three Months Ended September 30,
	2013			2012
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	1,736		$	(4,500	)
Natural gas sales		(2,779	)		(5,501	)
Total cash settlements		(1,043	)		(10,001	)

Commodity Derivative Instruments designated as hedging instruments:
Loss on derivative financial instruments Ineffective portion of commodity derivative instruments		1,562			4,257

Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments Realized mark to market (gain) loss		(574	)		1,275
Unrealized mark to market (gain) loss		453			86
Total loss on derivative financial instruments		1,441			5,618
Total (gain) loss	$	398		$	(4,383	)

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

Location of (Gain) Loss	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Three Months Ended September 30, 2013
Commodity Derivative Instruments	$	19,503
Revenues			$	(4,776	)
Loss on derivative financial instruments						$	1,562
Total (gain) loss	$	19,503	$	(4,776	)	$	1,562

Three Months Ended September 30, 2012
Commodity Derivative Instruments	$	31,382
Revenues			$	(6,851	)
Loss on derivative financial instruments						$	4,257
Total (gain) loss	$	31,382	$	(6, 851	)	$	4,257

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Reconciliation of the components of AOCI representing all the reclassifications out of AOCI to income for the periods presented is as follow (in thousands):

	Before Tax			After Tax			Location Where Consolidated Net Income is Presented
Three months ended September 30, 2013
Unrealized (gain) loss on derivatives at beginning of period	$	(40,464	)	$	(26,300	)
Unrealized change in fair value		21,094			13,711
Ineffective portion reclassified to earnings during the period		1,562			1,015		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		7,348			4,777		Revenues
Unrealized (gain) loss on derivatives at end of period	$	(10,460	)	$	(6,797	)

Three months ended September 30, 2012
Unrealized (gain) loss on derivatives at beginning of period	$	(88,620	)	$	(57,603	)
Unrealized change in fair value		33,483			21,764
Ineffective portion reclassified to earnings during the period		4,257			2,766		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		10,540			6,852		Revenues
Unrealized (gain) loss on derivatives at end of period	$	(40,340	)	$	(26,221	)

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $6.7 million ($4.4 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At September 30, 2013, we had no deposits for collateral with our counterparties.

Note 9 – 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, 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 Topic 740 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. We allocate income tax expense and deferred tax items between affiliates as if each affiliate prepared a separate U.S. income tax return for the year-to-date reporting period. We have recorded no income tax related intercompany balances with affiliates.

We have a remaining valuation allowance of $22.5 million related to certain State of Louisiana net operating loss carryovers that we do not currently believe, on a more likely-than-not basis, are realizable due to our current focus on offshore operations. While the consolidated group has not made a cash income tax payment in this quarter, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (“AMT”) in subsequent quarters may be required. We are a party to an intercompany agreement whereby we would be responsible for funding consolidated US federal income tax payments. We expect this AMT to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.

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Note 10 – Supplemental Cash Flow Information

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

	Three Months Ended September 30,
	2013		2012

Cash paid for interest	$	—	$	370
Cash paid for income taxes		2,856		—

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

	Three Months Ended September 30,
	2013		2012

Financing of insurance premiums	$	2,355	$	8,534
Derivative instruments premium financing		698		—
Additions to property and equipment by recognizing asset retirement obligations		14,151		3,550

Note 11 - Related Party Transactions

During the three months ended September 30, 2013 we paid dividends of $82 million to our Parent. During the three months ended September 30, 2013 and 2012, we returned net capital contributions of $13.1 million and $32.3 million, respectively, to our Parent.

On November 21, 2011, we advanced $65.0 million under a promissory note formalized on December 16, 2011 to Bermuda, our indirect parent, bearing a simple interest of 2.78% per annum. The note matures on December 16, 2021. Energy XXI, Inc. has an option to prepay this note in whole or in part at any time, without any penalty or premium. Interest and principal are payable at maturity. Interest on the note receivable amounted to approximately $481,000 and $456,000 for the three months ended September 30, 2013 and 2012, respectively. Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of September 30, 2013.

We have no employees; instead we receive 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 both the three months ended September 30, 2013 and 2012 was approximately $21.6 million, and is included in general and administrative expense.

The Company reimbursed $1.1 million to its affiliate Energy XXI Insurance Limited for windstorm insurance coverage. The coverage period is from May 25, 2012 through May 25, 2013.

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 effect on our consolidated financial position, results of operations or cash flows.

Letters of Credit and Performance Bonds. We had $225 million in letters of credit and $44.5 million of performance bonds outstanding as of September 30, 2013.

Drilling Rig Commitments. The drilling rig commitments represent minimum future expenditures for drilling rig services. The expenditures for drilling rig services will exceed such minimum amounts to the extent we utilize the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract. As of September 30, 2013, we have entered into three drilling rig commitments

1) June 30, 2013 to April 10, 2014 at $49,000 per day

2) October 1, 2013 to June 30, 2014 at $125,000 per day

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

At September 30, 2013, future minimum commitments under these contracts totaled $90.4 million.

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Note 13 — Fair Value of Financial Instruments

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

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

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

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

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

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

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

During the quarter ended September 30, 2013, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 2 financial instruments (in thousands):

	September 30, 2013		June 30, 2013
Assets:
Oil and natural gas derivatives	$	56,490	$	96,455

Liabilities:
Oil and natural gas derivatives	$	29,690	$	36,180

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Note 14 — Prepayments and Accrued Liabilities

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

	September 30, 2013		June 30, 2013
Prepaid expenses and other current assets
Advances to joint interest partners	$	25,025	$	13,936
Insurance		20,303		28,417
Inventory		4,135		4,094
Royalty deposit		2,333		1,210
Other		181		207
Total prepaid expenses and other current assets	$	51,977	$	47,864

Accrued liabilities
Advances from joint interest partners	$	525	$	1,348
Interest		28,181		5,733
Accrued hedge payable		2,919		2,214
Undistributed oil and gas proceeds		30,387		47,766
Other		1,371		1,273
Total accrued liabilities	$	63,383	$	58,334

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Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - November 18, 2013

Attached files

Energy XXI Ltd Reports