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

DECEMBER 31, 2013

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 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)

	December 31,			June 30,
	2013			2013
	(Unaudited)
ASSETS
CURRENT ASSETS
Restricted cash	$	746		$	—
Receivables:
Oil and natural gas sales		130,398			132,521
Joint interest billings		5,647			9,505
Insurance and other		6,175			5,367
Prepaid expenses and other current assets		40,914			47,864
Derivative financial instruments		7,731			38,389
TOTAL CURRENT ASSETS		191,611			233,646

Oil and gas properties-net – full cost method of accounting, including $251.4 million and $422.6 million of unevaluated properties not being amortized at December 31, 2013 and June 30, 2013, respectively		3,523,881			3,289,505
Other Assets
Note receivable from Energy XXI, Inc.		68,898			67,935
Derivative financial instruments		501			21,926
Debt issuance costs, net of accumulated amortization		31,478			24,791

TOTAL ASSETS	$	3,816,369		$	3,637,803

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	197,407		$	219,822
Accrued liabilities		43,148			58,334
Notes payable		10,288			22,349
Asset retirement obligations		29,911			29,500
Derivative financial instruments		1,820			40
Current maturities of long-term debt		12,083			18,838
TOTAL CURRENT LIABILITIES		294,657			348,883

Long-term debt, less current maturities		1,655,800			1,344,843
Deferred taxes		173,372			153,805
Asset retirement obligations		277,173			258,318
Derivative financial instruments		932			—
Other liabilities		1,429			—
TOTAL LIABILITIES		2,403,363			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		1,421,191			1,426,349
Retained earnings (accumulated deficit)		(3,794	)		79,304
Accumulated other comprehensive income (loss), net of
income taxes		(4,392	)		26,300
TOTAL STOCKHOLDER’S EQUITY		1,413,006			1,531,954

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	3,816,369		$	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						Six Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(In Thousands)
Revenues
Oil sales	$	262,230		$	285,824		$	551,459		$	533,154
Natural gas sales		34,586			34,695			69,949			57,592
Total Revenues		296,816			320,519			621,408			590,746

Costs and Expenses
Lease operating		93,789			85,922			179,552			168,403
Production taxes		1,189			1,166			2,587			2,413
Gathering and transportation		5,978			6,098			11,323			14,089
Depreciation, depletion and amortization		102,511			104,926			201,973			188,896
Accretion of asset retirement obligations		7,425			7,756			14,751			15,408
General and administrative		15,163			17,841			36.492			39,934
Loss (gain) on derivative financial instruments		5,722			902			7,163			6,520
Total Costs and Expenses		231,777			224,611			453,841			435,663

Operating Income		65,039			95,908			167,567			155,083

Other Income (Expense)
Other income		487			471			970			928
Interest expense		(35,837	)		(27,008	)		(65,441	)		(53,526	)
Total Other Expense		(35,350	)		(26,537	)		(64,471	)		(52,598	)

Income Before Income Taxes		29,689			69,371			103,096			102,485

Income Tax Expense		10,401			24,279			36,094			36,044

Net Income	$	19,288		$	45,092		$	67,002		$	66,441

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 Ended December 31,						Six Months Ended December 31,
	2013			2012			2013			2012

Net Income	$	19,288		$	45,092		$	67,002		$	66,441

Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		(8,858	)		1,400			(31,515	)		(36,341	)
Effective portion reclassified to earnings during the period		(8,357	)		(10,797	)		(15,704	)		(21,337	)
Total Other Comprehensive Income (Loss)		(17,215	)		(9,397	)		(47,219	)		(57,678	)
Income Tax (Expense) Benefit		6,025			3,289			16,527			20,188
Net Other Comprehensive Loss		(11,190	)		(6,108	)		(30,692	)		(37,490	)

Comprehensive Income (Loss)	$	(8,098	)	$	38,984		$	36,310		$	28,951

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Six Months Ended
	December 31,
	2013			2012
	(In Thousands)
Cash Flows from Operating Activities
Net income	$	67,002		$	66,441
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Deferred income tax expense		36,094			36,045
Change in derivative financial instruments
Proceeds from sale of derivative instruments		—			61
Other – net		(364	)		(13,885	)
Accretion of asset retirement obligations		14,751			15,408
Depreciation, depletion and amortization		201,973			188,896
Amortization of debt issuance costs		3,250			3,798
Changes in operating assets and liabilities:
Accounts receivables		16,870			(7,930	)
Prepaid expenses and other current assets		(5,111	)		(7,862	)
Asset retirement obligations		(34,038	)		(24,809	)
Accounts payable and other liabilities		(36,171	)		11,067
Net Cash Provided by Operating Activities		264,256			267,230

Cash Flows from Investing Activities
Acquisitions		(12,564	)		(41,156	)
Capital expenditures		(386,979	)		(370,138	)
Insurance payments received		—			—
Transfer to restricted cash		(746	)		—
Proceeds from the sale of properties		1,748			—
Other		—			(6	)
Net Cash Used in Investing Activities		(398,541	)		(411,300	)

Cash Flows from Financing Activities
Dividends to parent		(150,100	)		—
Proceeds from long-term debt		1,428,117			603,959
Payments on long-term debt		(1,127,673	)		(481,158	)
Advance to Energy XXI, Inc.		(963	)		(911	)
Returns to parent		(5,158	)		(23,041	)
Debt issuance costs and other		(9,938	)		(173	)
Net Cash Provided by Financing Activities		134,285			98,676

Net 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

DECEMBER 31, 2013

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

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

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

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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. The objective targets at Pendragon well, the initial prospect, were not reached as it encountered mechanical issues and was plugged and abandoned. Subsequently, we began drilling the Merlin well located at Vermilion Block 179; the Merlin well did not encounter any commercial hydrocarbons and was plugged and abandoned. We are currently analyzing the Pendragon and Merlin wells’ data to determine the future drilling activities on the Vermilion Block.

Revenues and expenses related to the GOM Interests from the closing date of October 17, 2012 are included in our consolidated statements of income. The acquisition of the GOM Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. As of December 31, 2013, the Company’s measurement period adjustments were complete. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on 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. As of December 31, 2013, the Company’s measurement period adjustments were complete. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

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

McMoRan oil and gas properties interests acquisition

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

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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. As of December 31, 2013, the Company’s measurement period adjustments were complete. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

	January 17, 2013 As Initially Reported			Measurement Period Adjustment			January 17, 2013 As Adjusted

Oil and natural gas properties – evaluated	$	62,499		$	17,184		$	79,683
Oil and natural gas properties – unevaluated		17,184			(17,184	)		—
Asset retirement obligations		(382	)					(382	)
Cash paid	$	79,301		$	—		$	79,301

RoDa oil and gas properties interests acquisition

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

Revenues and expenses related to the RoDa Interests from the closing date of March 14, 2013 are included in our consolidated statements of income. The acquisition of the RoDa Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the 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 was effective as of June 1, 2013. We are the operator of these properties.

Revenues and expenses related to the West Delta Interests are included in our consolidated statements of income from July 1, 2013. The acquisition of West Delta Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the 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

Black Elk Interest

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

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

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

* Net working capital includes payables.

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.

Apache Joint Venture

On February 1, 2013, we entered into an Exploration Agreement (the “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 $32.9 million was incurred through December 31, 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 December 31, 2013 were approximately $16.5 million.

As of December 31, 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):

	December 31,		June 30,
	2013		2013
Oil and gas properties
Proved properties	$	5,943,266	$	5,335,737
Less: accumulated depreciation, depletion, amortization and impairment		2,670,755		2,468,783
Proved properties		3,272,511		2,866,954
Unevaluated properties		251,370		422,551
Oil and gas properties-net	$	3,523,881	$	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 exploratory wells in progress. Costs associated with these unproved properties are transferred to evaluated properties upon the earlier of (i) when a determination is made whether there are any proved reserves related to the properties, or (ii) amortized over a period of time of not more than four years.

Exploratory wells in progress include $188.0 million in costs primarily related to our participation with Freeport-McMoRan Oil & Gas LLC (Freeport McMoRan) who operates several prospects in the ultra-deep shelf and onshore area (“ultra-deep trend”) in the Gulf of Mexico and to the joint ventures with Fieldwood Energy, LLC 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 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.

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As of December 31, 2013, the costs associated with our major projects and their status was as follows (in millions):

Project Name	Cost		Status

Davy Jones Facilities	$	21.6	Facilities cost in Davy Jones field for well operations.
Davy Jones Offset Appraisal Well		51.8	Completion operations have commenced, flow testing expected in the first half of calendar year 2014.
Blackbeard East		50.4	Plans to begin development of the shallow zones in late calendar year 2014.
Lomond North		31.3	Completion operations in progress to test lower Wilcox and Cretaceous objectives
Other		32.9
Total	$	188.0

Note 5 – Long-Term Debt

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

	December 31,		June 30,
	2013		2013

Revolving credit facility	$	152,307	$	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		15,576		24,681
Total debt		1,667,883		1,363,681
Less current maturities		12,083		18,838
Total long-term debt	$	1,655,800	$	1,344,843

Maturities of long-term debt as of December 31, 2013 are as follows (in thousands):

Twelve Months Ended December 31,

2014	$	12,083
2015		3,493
2016		—
2017		750,000
2018		152,307
Thereafter		750,000
Total	$	1,667,883

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 dividend payments 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 Bermuda was modified in subsequent amendments.

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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 our 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 our 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.

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 those 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 December 31, 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.

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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 December 31, 2013 was $838 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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 December 31, 2013 was $268 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 our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

We believe that the fair value of the $500 million of 7.50% Senior Notes outstanding as of December 31, 2013 was $525 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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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 our 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”.

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 December 31, 2013 and June 30, 2013, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $15.6 million and $24.7 million, respectively.

Interest Expense

For the three months and six months ended December 31, 2013 and 2012, interest expense consisted of the following (in thousands):

	Three Months Ended December 31,				Six Months Ended December 31,
	2013		2012		2013		2012

Revolving credit facility	$	2,326	$	2,676	$	7,545	$	4,855
9.25% Senior Notes due 2017		17,344		17,344		34,688		34,688
7.75% Senior Notes due 2019		4,844		4,844		9,688		9,688
7.50% Senior Notes due 2021		9,271		—		9,792		—
Amortization of debt issue cost - Revolving credit facility		855		1,259		1,661		2,501
Amortization of debt issue cost – 9.25% Senior Notes due 2017		552		551		1,104		1,103
Amortization of debt issue cost – 7.75% Senior Notes due 2019		97		97		194		194
Amortization of debt issue cost – 7.50% Senior Notes due 2021		260		—		260		—
Derivative instruments financing and other		288		237		509		497
	$	35,837	$	27,008	$	65,441	$	53,526

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 an additional 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 matures on April 26, 2014. The balance outstanding as of December 31, 2013 was $9.0 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 matures on June 1, 2014. The balance outstanding as of December 31, 2013 was $1.3 million.

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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 acquired		10,503
Liabilities incurred		28,050
Liabilities settled		(34,038	)
Accretion expense		14,751
Total balance at December 31, 2013		307,084
Less current portion		29,911
Long-term balance at December 31, 2013	$	277,173

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 December 31, 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 December 31, 2013, all of the monetized amounts remaining in OCI were recognized in income.

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 were recognized in income over the life of the underlying hedge contracts through December 31, 2013. As of December 31, 2013, all of the amounts remaining in deferred hedge revenue were recognized in income.

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As of December 31, 2013, we had the following open crude oil derivative positions:

					Weighted Average Contract Price
					Collars
Period	Type of Contract	Index	Volumes (MBbls)		Sub Floor		Floor		Ceiling

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		3,650		71.00		91.00		113.75

As of December 31, 2013, we had the following open natural gas derivative positions:

Weighted Average Contract Price

Collars

Period

Type of Contract

Index

Volumes

(MMBtu)

Sub Floor

Floor

Ceiling

January 2014 – December 2014

Three-Way Collars

NYMEX-HH

18,250

3.35

4.00

4.61

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

	Asset Derivative Instruments						Liability Derivative Instruments
	December 31, 2013			June 30, 2013			December 31, 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	$	21,892	Current	$	52,216	Current	$	15,981	Current	$	14,609
	Non-Current		15,705	Non-Current		42,263	Non-Current		16,136	Non-Current		20,337
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments	Current		—	Current		1,976	Current		—	Current		1,234
	Non-Current		—	Non-Current		—	Non-Current		—	Non-Current		—
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement			37,597			96,455			32,117			36,180

Derivative financial instruments	Current		(14,161)	Current		(15,803)	Current		(14,161)	Current		(15,803)
	Non-Current		(15,204)	Non-Current		(20,337)	Non-Current		(15,204)	Non-Current		(20,337)
Gross amounts offset in Balance Sheet			(29,365)			(36,140)			(29,365)			(36,140)
Net amounts presented in Balance Sheet		$	8,232		$	60,315		$	2,752		$	40

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

	Three Months Ended December 31,						Six Months Ended December 31,
	2013			2012			2013			2012
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	1,397		$	(4,870	)	$	3,134		$	(9,370	)
Natural gas sales		(3,448	)		(5,039	)		(6,227	)		(10,540	)
Total cash settlements		(2,051	)		(9,909	)		(3,093	)		(19,910	)

Commodity Derivative Instruments designated as hedging instruments:
Loss on derivative financial instruments Ineffective portion of commodity derivative instruments		6,112			360			7,674			4,616

Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments Realized mark to market (gain) loss		(645	)		697			(1,219	)		1,973
Unrealized mark to market (gain) loss		255			(155	)		708			(69	)
Total loss on derivative financial instruments		5,722			902			7,163			6,520
Total (gain) loss	$	3,671		$	(9,007	)	$	4,070		$	(13,390	)

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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 December 31, 2013
Commodity Derivative Instruments	$	11,190
Revenues			$	(5,432	)
Loss on derivative financial instruments						$	6,112
Total (gain) loss	$	11,190	$	(5,432	)	$	6,112

Three Months Ended December 31, 2012
Commodity Derivative Instruments	$	6,108
Revenues			$	(7,018	)
Loss on derivative financial instruments						$	360
Total (gain) loss	$	6,108	$	(7,018	)	$	360

Six Months Ended December 31, 2013
Commodity Derivative Instruments	$	30,692
Revenues			$	(10,208	)
Loss on derivative financial instruments						$	7,674
Total (gain) loss	$	30,692	$	(10,208	)	$	7,674

Six Months Ended December 31, 2012
Commodity Derivative Instruments	$	37,490
Revenues			$	(13,869	)
Loss on derivative financial instruments						$	4,616
Total (gain) loss	$	37,490	$	(13,869	)	$	4,616

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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 December 31, 2013
Unrealized gain on derivatives at beginning of period	$	(10,457	)	$	(6,797	)
Unrealized change in fair value		2,746			1,784
Ineffective portion reclassified to earnings during the period		6,112			3,973		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		8,357			5,432		Revenues
Unrealized loss on derivatives at end of period	$	6,758		$	4,392

Three months ended December 31, 2012
Unrealized gain on derivatives at beginning of period	$	(40,340	)	$	(26,221	)
Unrealized change in fair value		(1,760	)		(1,144	)
Ineffective portion reclassified to earnings during the period		360			234		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		10,797			7,018		Revenues
Unrealized gain on derivatives at end of period	$	(30,943	)	$	(20,113	)

	Before Tax			After Tax			Location Where Consolidated Net Income is Presented
Six months ended December 31, 2013
Unrealized gain on derivatives at beginning of period	$	(40,461	)	$	(26,300	)
Unrealized change in fair value		23,841			15,497
Ineffective portion reclassified to earnings during the period		7,674			4,987		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		15,704			10,208		Revenues
Unrealized loss on derivatives at end of period	$	6,758		$	4,392

Six months ended December 31, 2012
Unrealized gain on derivatives at beginning of period	$	(88,620	)	$	(57,603	)
Unrealized change in fair value		31,724			20,621
Ineffective portion reclassified to earnings during the period		4,616			3,000		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		21,337			13,869		Revenues
Unrealized gain on derivatives at end of period	$	(30,943	)	$	(20,113	)

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a loss of $3.9 million ($2.5 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 December 31, 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.

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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.

Note 10 – Supplemental Cash Flow Information

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

	Three Months Ended December 31,				Six Months Ended December 31,
	2013		2012		2013		2012

Cash paid for interest	$	55,151	$	47,160	$	60,917	$	47,549
Cash paid for income taxes		266		—		3,122		—

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

	Three Months Ended December 31,				Six Months Ended December 31,
	2013		2012		2013		2012

Financing of insurance premiums	$	—	$	11,331	$	2,355	$	19,865
Derivative instruments premium financing		2,795		2,138		3,493		2,138
Additions to property and equipment by recognizing asset retirement obligations		13,899		6,240		28,050		9,790

Note 11 - Related Party Transactions

During the six months ended December 31, 2013 we paid dividends of $150.1 million to our Parent. During the six months ended December 31, 2013 and 2012, we returned net capital contributions of $5.2 million and $23.0 million, respectively, to our Parent.

On November 21, 2011, we advanced $65.0 million under a promissory note formalized on December 16, 2011 to Energy XXI, Inc., our indirect parent, bearing a simple interest of 2.78% per annum. The note matures on December 16, 2021. Energy XXI, Inc. has an option to prepay this note in whole or in part at any time, without any penalty or premium. Interest and principal are payable at maturity. Interest on the note receivable amounted to approximately $482,000 and $963,000 for the three months and six months ended December 31, 2013, respectively. Interest on the note receivable amounted to approximately $455,000 and $911,000 for the three months and six months ended December 31, 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 December 31, 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 the three months and six months ended December 31, 2013 was approximately $14.8 million and $36.4 million, respectively, and cost of these services for the three months and six months ended December 31, 2012 was approximately $17.7 million, $39.3 million, respectively and is included in general and administrative expense.

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

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.

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Letters of Credit and Performance Bonds. We had $225.3 million in letters of credit and $44.5 million of performance bonds outstanding as of December 31, 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 December 31, 2013, we have entered into the following drilling rig commitments:

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

2) October 31, 2013 to June 30, 2014 at $125,000 per day

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

4) November 22, 2013 to February 10, 2014 at $120,000 per day

5) February 1, 2014 to January 31, 2015 at $50,000 per day

At December 31, 2013, future minimum commitments under these contracts totaled $84.7 million.

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 8 — 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.

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During the six months ended December 31, 2013, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

	Level 2
	December 31, 2013		June 30, 2013
	December 31, 2013		June 30, 2013

Assets:
Oil and natural gas derivatives	$	37,597	$	96,455

Liabilities:
Oil and natural gas derivatives	$	32,117	$	36,180

Note 14 — Prepayments and Accrued Liabilities

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

	December 31, 2013		June 30, 2013
Prepaid expenses and other current assets
Advances to joint interest partners	$	18,562	$	13,936
Insurance		12,786		28,417
Inventory		4,077		4,094
Royalty deposit		2,333		1,210
Other		3,156		207
Total prepaid expenses and other current assets	$	40,914	$	47,864

Accrued liabilities
Advances from joint interest partners	$	374	$	1,348
Interest		8,574		5,733
Accrued hedge payable		2,196		2,214
Undistributed oil and gas proceeds		31,469		47,766
Other		535		1,273
Total accrued liabilities	$	43,148	$	58,334

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Attached files

Energy XXI Ltd Reports

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