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

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

Exhibit 99.1

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2013

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

MARCH 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		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)

	March 31,		June 30,
	2013		2012
ASSETS	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—	$	45,394
Receivables:
Oil and natural gas sales		138,522		126,107
Joint interest billings		9,260		3,840
Insurance and other		3,462		4,077
Prepaid expenses and other current assets		19,820		51,103
Derivative financial instruments		23,833		32,301
TOTAL CURRENT ASSETS		194,897		262,822
Oil and gas properties – full cost method of accounting, including $539.4 million and $418.8 million unevaluated properties at March 31, 2013 and June 30, 2012, respectively, net of accumulated depreciation, depletion, amortization and impairment		3,148,239		2,698,213
Other assets
Note receivable from Energy XXI, Inc.		67,458		66,099
Derivative financial instruments		16,959		45,232
Debt issuance costs, net of accumulated amortization		21,344		26,872

TOTAL ASSETS	$	3,448,897	$	3,099,238

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	173,325	$	156,388
Accrued liabilities		90,314		60,095
Notes payable		731		22,211
Asset retirement obligations		30,130		34,457
Derivative financial instruments		112		—
Current maturities of long-term debt		22,654		3,864
TOTAL CURRENT LIABILITIES		317,266		277,015
Long-term debt, less current maturities		1,221,564		1,013,523
Deferred income taxes		126,125		87,229
Asset retirement obligations		283,317		266,958
Derivative financial instruments		561		—
TOTAL LIABILITIES		1,948,833		1,644,725
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDER’S EQUITY
Common stock, $0.01 par value, 1,000,000 shares
authorized and 100,000 shares issued and outstanding
at March 31, 2013 and June 30, 2012		1		1
Additional paid-in capital		1,428,206		1,454,081
Accumulated earnings (deficit)		57,712		(57,172	)
Accumulated other comprehensive income, net of income taxes		14,145		57,603
TOTAL STOCKHOLDER’S EQUITY		1,500,064		1,454,513

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	3,448,897	$	3,099,238

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 March 31,						Nine Months Ended March 31,
	2013			2012			2013			2012
Revenues
Oil sales	$	274,364		$	312,714		$	807,518		$	868,978
Natural gas sales		29,410			23,282			87,002			92,479
Total Revenues		303,774			335,996			894,520			961,457
Costs and Expenses
Lease operating		86,305			78,447			254,708			223,614
Production taxes		1,352			1,499			3,765			4,847
Gathering and transportation		4,411			2,465			18,500			12,013
Depreciation, depletion and amortization		87,759			87,706			276,655			258,692
Accretion of asset retirement obligations		7.649			9,762			23,057			29,253
General and administrative		15,072			24,287			55,006			63,061
(Gain) loss on derivative financial instruments		(622	)		3,412			5,898			(2,589	)
Total Costs and Expenses		201,926			207,578			637,589			588,891
Operating Income		101,848			128,418			256,931			372,566
Other Income (Expense)
Other income		443			518			1,371			738
Interest expense		(27,596	)		(26,852	)		(81,122	)		(82,294	)
Total Other Expense		(27,153	)		(26,334	)		(79,751	)		(81,556	)
Income Before Income Taxes		74,695			102,084			177,180			291,010
Income Tax Expense		26,252			46,580			62,296			62,792
Net Income	$	48,443		$	55,504		$	114,884		$	228,218

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

(Unaudited)

	Three Months Ended March 31,						Nine Months Ended March 31,
	2013			2012			2013			2012

Net Income	$	48,443		$	55,504		$	114,884		$	228,218

Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		(2,017	)		(59,090	)		(38,356	)		106,915
Effective portion reclassified to earnings during the period		(7,165	)		(2,075	)		(28,502	)		(25,627	)
Total Other Comprehensive Income (Loss)		(9,182	)		(61,165	)		(66,858	)		81,288
Income Tax (Expense) Benefit		3,214			21,408			23,400			(28,451	)
Net Other Comprehensive Income (Loss)		(5,968	)		(39,757	)		(43,458	)		52,837

Comprehensive Income	$	42,475		$	15,747		$	71,426		$	281,055

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)


	Nine Months Ended March 31,
	2013			2012
Cash Flows From Operating Activities
Net income	$	114,884		$	228,218
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		276,655			258,692
Deferred income tax expense		62,296			62,942
Change in derivative financial instruments
Proceeds from sale of derivative instruments		735			66,522
Other – net		(19,326	)		(36,641	))
Accretion of asset retirement obligations		23,057			29,253
Amortization and write-off of debt issuance costs		5,677			5,591
Changes in operating assets and liabilities
Accounts receivable		(9,475	)		(26,508	))
Prepaid expenses and other current assets		9,803			(7,040	)
Settlement of asset retirement obligations		(29,570	)		(6,563	))
Accounts payable and accrued liabilities		47,154			899
Net Cash Provided by Operating Activities		481,890			575,365
Cash Flows from Investing Activities
Acquisitions		(153,722	)		(6,212	)
Capital expenditures		(554,408	)		(390,419	))
Insurance payments received		—			6,472
Proceeds from the sale of properties and other		(6	)		2,970
Net Cash Used in Investing Activities		(708,136	)		(387,189	))
Cash Flows from Financing Activities
Proceeds from long-term debt		1,136,949			707,761
Payments on long-term debt		(928,713	)		(818,787	))
Advance to Energy XXI, Inc.		(1,359	)		(65,649	)
Contributions (return) from (to) parent		(25,875	)		5,002
Payments for debt issuance costs and other		(150	)		(864	))
Net Cash Provided by (Used in) Financing Activities		180,852			(172,537	)
Net Increase (Decrease) in Cash and Cash Equivalents		(45,394	)		15,639
Cash and Cash Equivalents, beginning of period		45,394			—
Cash and Cash Equivalents, end of period	$	—		$	15,639

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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 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, 2012.

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 (“AOCI”) 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 do not expect the adoption ASU 2013-02 to have any effect on our consolidated financial position, results of operations or cash flows, other than presentation.

Note 3 – Acquisitions

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 $33.5 million. The GOM Interests cover 5,000 gross acres on Vermilion Block 164 (“VM 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 VM 164 in shallow waters on the Gulf of Mexico shelf. We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012. Our total capital commitment for the joint venture in calendar year 2013 is estimated at $75 million, assuming successful completion of two earning wells.

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	$	11,088
Oil and natural gas properties – unevaluated		27,721
Asset retirement obligations		(5,353	)
Cash paid	$	33,456

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 VM 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	$	1,716
Oil and natural gas properties – unevaluated		6,571
Asset retirement obligations		(1,090	)
Cash paid	$	7,197

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 $80 million. This acquisition is effective 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. 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	$	63,186
Oil and natural gas properties – unevaluated		17,184
Net working capital		12
Asset retirement obligations		(382	)
Cash paid	$	80,000

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 $34 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	$	33,615
Net working capital		500
Asset retirement obligations		(115	)
Cash paid	$	34,000

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 (“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 Agreement, which expires on February 1, 2018.

The area of mutual interest (“AMI”) under this 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. 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.

As of March 31, 2013, we paid consideration of approximately $2.5 million, being our participation interest, to Apache for non-producing primary-term leases.

Note 4 – Property and Equipment

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

	March 31,		June 30,
	2013		2012
Oil and gas properties
Proved properties	$	4,982,071	$	4,375,984
Less: Accumulated depreciation, depletion, amortization and impairment		2,373,186		2,096,531
Proved properties		2,608,885		2,279,453
Unproved properties		539,354		418,760
Total property and equipment – net of accumulated depreciation, depletion, amortization and impairment	$	3,148,239	$	2,698,213

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Note 5 – Long-Term Debt

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

	March 31,		June 30,
	2013		2012

Revolving credit facility	$	212,831	$	—
9.25% Senior Notes due 2017		750,000		750,000
7.75% Senior Notes due 2019		250,000		250,000
Derivative instruments premium financing		31,387		17,387
Total debt		1,244,218		1,017,387
Less current maturities		22,654		3,864
Total long-term debt	$	1,221,564	$	1,013,523

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

Twelve Months Ended March 31,

2014	$	22,654
2015		221,564
2016		—
2017		—
2018		750,000
Thereafter		250,000
Total	$	1,244,218

Revolving Credit Facility

We entered into the second amended and restated first lien credit agreement (“First Lien Credit Agreement”) in May 2011. This facility, amended most recently on May 1, 2013, 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 us 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.

On May 24, 2012, we entered into the Second Amendment (the “Second Amendment”) to the First Lien Credit Agreement which provided further increased flexibility to make payments from us to Bermuda and/or our other subsidiaries. The Second Amendment includes the following: (a) removal of limitations on 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 increases 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 includes the following: (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 now can make such 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.

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) EGC’s 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, Bermuda is subject to various other covenants including, but not limited to, those limiting their ability to declare and pay dividends or other payments, their ability to incur debt, changes in control, their ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

As of March 31, 2013, we were in compliance with all covenants under our First Lien Credit Agreement.

High Yield Facilities

9.25% Senior Notes

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

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of March 31, 2013 was $848.9 million based on quoted prices. There is no active market for the 9.25% Senior Notes; therefore, the fair value is classified within Level 2.

The 9.25% Senior Notes are fully and unconditionally guaranteed by Bermuda and each of our existing and future material domestic subsidiaries.

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7.75% Senior Notes

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

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

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 is defined in the indenture governing the 7.75% Senior Notes.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of March 31, 2013 was $271.3 million based on quoted prices. There is no active market for the 7.75% Senior Notes; therefore, the fair value is classified within Level 2.

The 7.75% Senior Notes are fully and unconditionally guaranteed by Bermuda and each of our existing and future material domestic subsidiaries.

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 March 31, 2013 and June 30, 2012, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $31.4 million and $17.4 million, respectively.

Interest Expense

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

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012

Revolving credit facility	$	3,330	$	2,201	$	8,185	$	7,291
9.25% Senior Notes due 2017		17,343		17,344		52,031		52,031
7.75% Senior Notes due 2019		4,843		4,843		14,531		14,531
Amortization of debt issue cost - Revolving credit facility		1,231		1,238		3,732		3,645
Amortization of debt issue cost – 9.25% Senior Notes due 2017		552		552		1,655		1,655
Amortization of debt issue cost – 7.75% Senior Notes due 2019		97		97		291		291
Derivative instruments financing and other		200		577		697		2,850
Total	$	27,596	$	26,852	$	81,122	$	82,294

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 is for a total face amount of $3.6 million and bears interest at an annual rate of 1.667%. The note amortizes over the remaining term of the insurance, which matures May 1, 2013. The balance outstanding as of March 31, 2013 was $0.7 million.

In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums. The note was for a total face amount of $0.6 million and bears interest at an annual rate of 1.774%. The note amortizes over the remaining term of the insurance, which matures October 23, 2013. The balance outstanding as of March 31, 2013 was $0.3 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, 2012	$	301,415
Liabilities acquired		6,940
Liabilities incurred		11,605
Liabilities settled		(29,570	)
Accretion expense		23,057
Total balance at March 31, 2013		313,447
Less current portion		30,130
Long-term balance at March 31, 2013	$	283,317

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

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. Historically the basis differential between HLS and WTI has been relatively small and predictable. Over the past five years, HLS has averaged approximately $1 per barrel premium to WTI. Since the beginning of 2011, the HLS/WTI basis differential and volatility has increased with HLS carrying as much as a $30 per barrel premium to WTI. During the quarter ended September 30, 2011, 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.

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We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended March 31, 2013, and received $181.1 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 March 31, 2013, we had $13.5 million of monetized amounts remaining in OCI of which $4.5 million will be recognized during each of the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013, respectively.

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 March 31, 2013, we had $2.0 million in deferred hedge revenue of which $0.6 million, $0.7 million, and $0.7 million will be recognized during the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013, respectively.

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

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

April 2013 - December 2013	Three-Way Collars	Oil-Brent-IPE		2,570	(1)			$	85.72	$	105.72	$	126.72
April 2013 - December 2013	Put Spreads	Oil-Brent-IPE		1,830					87.00		106.25
April 2013 - December 2013	Three-Way Collars	NYMEX-WTI		1,375					70.00		90.00		136.32
April 2013 - December 2013	Collars	NYMEX-WTI		963							73.57		105.63
April 2013 - December 2013	Swaps	NYMEX-WTI		138		$	86.60
April 2013 - December 2013	Swaps	NYMEX-WTI		(138	)		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		1,825					72.00		92.00		111.56

(1)

The Oil-Brent-IPE three-way collars for the period from April 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 March 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

April 2013 - December 2013

Three-Way Collars

NYMEX-HH

8,250

4.07

4.93

5.87

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

	Asset Derivative Instruments						Liability Derivative Instruments
	March 31, 2013			June 30, 2012			March 31, 2013			June 30, 2012
	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	$	37,233	Current	$	66,716	Current	$	13,621	Current	$	34,462
	Non-Current		43,294	Non-Current		103,462	Non-Current		26,896	Non-Current		58,229
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments	Current		4,503	Current		46	Current		4,394	Current		—
Total		$	85,030		$	170,224		$	44,911		$	92,691

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

	Three Months Ended March 31,					Nine Months Ended March 31,
	2013		2012			2013		2012
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(1,084)	$	3,009		$	(10,455)	$	2,576
Natural gas sales		(2,340)		(4,128	)		(12,879)		(23,528	)
Total cash settlements		(3,424)		(1,119	)		(23,334)		(20,952	)
Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments		(816)		3,388			3,800		1,713
		(816)		3,388			3,800		1,713
Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market (gain) loss		(41)		24			1,932		(5,001	)
Unrealized mark to market (gain) loss		235		—			166		699
Total (gain) loss on derivative financial instruments		(622)		3,412			5,898		(2,589	)
Total (gain) loss	$	(4,046)	$	2,293		$	(17,436)	$	(23,541	)

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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 March 31, 2013
Commodity Derivative Instruments	$	5,968
Revenues				$	(4,657	)
(Gain) loss on derivative financial instruments							$	(816	)
Total	$	5,968		$	(4,657	)	$	(816	)
Three Months Ended March 31, 2012
Commodity Derivative Instruments	$	39,757
Revenues				$	(1,349	)
(Gain) loss on derivative financial instruments							$	3,388
Total	$	39,757		$	(1,349	)	$	3,388

Nine Months Ended March 31, 2013
Commodity Derivative Instruments	$	43,458
Revenues				$	(18,526	)
(Gain) loss on derivative financial instruments							$	3,800
Total	$	43,458		$	(18,526	)	$	3,800
Nine Months Ended March 31, 2012
Commodity Derivative Instruments	$	(52,837	)
Revenues				$	(16,658	)
(Gain) loss on derivative financial instruments							$	1,713
Total	$	(52,837	)	$	(16,658	)	$	1,713

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $15.9 million ($10.3 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position from counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At March 31, 2013, we had no deposits for collateral with our counterparties.

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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 USA, Inc., (the “U.S. Parent”) is the parent entity. Energy XXI (Bermuda) Limited, indirectly owns 100% of U.S. Parent, but is not a member of the U.S. consolidated group. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon the tax laws and rates of the United States as they apply to our current ownership structure. ASC 740 (formerly FAS 109) provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated financial reporting group should be based upon a reasonable allocation of the income tax amounts of that group. 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 $30.2 million (related to certain state of Louisiana tax attributes and other property matters). 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 (possibly as early as the fourth quarter of fiscal year 2013). We are a party to an intercompany agreement whereby we would be responsible for funding consolidated U.S. federal income tax payments. At this time, we do not believe the federal estimated income tax payments for this fiscal year will exceed $5 million. 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 — Related Party Transactions

During the nine months ended March 31, 2013 we returned capital of $25.9 million to our Parent and during the nine months ended March 31, 2012, our Parent contributed capital of $5.0 million to us.

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 $0.5 million and $1.4 million for the three and nine months ended March 31, 2013, respectively. Interest on the note receivable amounted to approximately $0.5 million and $0.6 million for the three and nine months ended March 31, 2012. Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of March 31, 2013.

The Company has no employees; instead it receives management services from Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company. Other services provided by Energy Services include legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services. Cost of these services for the three months and nine months ended March 31, 2013 were approximately $14.5 million and $53.8 million, respectively, and cost of these services for the three months and nine months ended March 31, 2012 were approximately $23.4 million, $62.2 million, respectively and is included in general and administrative expense.

Note 11 – Supplemental Cash Flow Information

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

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012

Cash paid for interest	$	3,329	$	4,698	$	50,768	$	56,721

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

	Three Months Ended March 31,						Nine Months Ended March 31,
	2013			2012			2013			2012

Financing of insurance premiums	$	(1,266	)	$	(8,558	)	$	(21,131	)	$	(19,215	)
Derivative instruments premium financing		12,780			15,557			14,001			12,869
Additions to property and equipment by recognizing asset retirement obligations		1,816			700			11,605			2,037

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 $225.3 million in letters of credit and $44.4 million of performance bonds outstanding as of March 31, 2013.

Drilling Rig Commitments. As of March 31, 2013, we have entered into seven drilling rig commitments:

1) January 16, 2013 to June 30, 2013 at $49,000 per day

2) January 1, 2013 to September 30, 2013 at $110,000 per day

3) January 1, 2013 to September 30, 2013 at $110,000 per day

4) March 5, 2013 to September 5, 2013 at $130,000 per day

5) October 2, 2012 to June 1, 2013 at $90,000 per day

6) February 15, 2013 to July 15, 2013 at $39,000 per day

7) March 15, 2013 to July 1, 2013 at $36,000 per day

At March 31, 2013, future minimum commitments under these contracts totaled $70.2 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.

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

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

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

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

The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

	Level 2
	March 31,		June 30,
	2013		2012
Assets:
Oil and natural gas derivatives	$	85,030	$	170,224

Liabilities:
Oil and natural gas derivatives	$	44,911	$	92,691

Note 14 — Prepayments and Accrued Liabilities

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

	March 31,		June 30,
	2013		2012

Prepaid expenses and other current assets
Advances to joint interest partners	$	3,059	$	12,966
Insurance		6,801		30,162
Inventory		4,127		4,849
Royalty deposit		1,961		2,443
Other		3,872		683
Total prepaid expenses and other current assets	$	19,820	$	51,103

Accrued liabilities
Advances from joint interest partners	$	10,264	$	301
Interest		28,037		3,721
Accrued hedge payable		4,228		136
Undistributed oil and gas proceeds		46,757		54,484
Other		1,028		1,453
Total accrued liabilities	$	90,314	$	60,095

Note 15 — Subsequent Events

EGC entered into the Fourth and Fifth Amendments to the First Lien Credit Agreement on April 9, 2013 and May 1, 2013, respectively. See Note 5 – Long-Term Debt of Notes to Consolidated Financial Statements in this Quarterly Report.

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Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - May 28, 2013

Attached files

Energy XXI Ltd Reports