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, 2012

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012

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)

	December 31,		June 30,
	2012		2012
ASSETS	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—	$	45,394
Receivables:
Oil and natural gas sales		136,349		126,107
Joint interest billings		5,558		3,840
Insurance and other		3,866		4,077
Prepaid expenses and other current assets		38,578		51,103
Derivative financial instruments		14,879		32,301
TOTAL CURRENT ASSETS		199,230		262,822

Oil and gas properties – full cost method of accounting, including $498.3 million and $418.8 million unevaluated properties at December 31, 2012 and June 30, 2012, respectively, net of accumulated depreciation, depletion, amortization and impairment		2,936,850		2,698,213
Other assets
Note receivable from Energy XXI, Inc.		67,010		66,099
Derivative financial instruments		20,744		45,232
Debt issuance costs, net of accumulated amortization		23,243		26,872

TOTAL ASSETS	$	3,247,077	$	3,099,238

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	180,411	$	156,388
Accrued liabilities		47,138		60,095
Notes payable		1,824		22,211
Asset retirement obligations		29,815		34,457
Derivative financial instruments		782		—
Current maturities of long-term debt		7,016		3,864
TOTAL CURRENT LIABILITIES		266,986		277,015
Long-term debt, less current maturities		1,135,520		1,013,523
Deferred income taxes		103,087		87,229
Asset retirement obligations		278,432		266,958
Derivative financial instruments		2,629		—
TOTAL LIABILITIES		1,786,654		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 December 31, 2012 and June 30, 2012		1		1
Additional paid-in capital		1,431,040		1,454,081
Accumulated deficit		9,269		(57,172	)
Accumulated other comprehensive income, net of income taxes		20,113		57,603
TOTAL STOCKHOLDER’S EQUITY		1,460,423		1,454,513

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	3,247,077	$	3,099,238

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
	(In Thousands)
Revenues
Oil sales	$	285,824		$	309,347		$	533,154		$	556,264
Natural gas sales		34,695			31,231			57,592			69,197
Total Revenues		320,519			340,578			590,746			625,461

Costs and Expenses
Lease operating		85,922			74,134			168,403			145,167
Production taxes		1,166			1,174			2,413			3,348
Gathering and transportation		6,098			3,395			14,089			9,548
Depreciation, depletion and amortization		104,926			86,878			188,896			170,986
Accretion of asset retirement obligations		7,756			9,803			15,408			19,491
General and administrative		17,841			20,705			39,934			38,774
Loss (gain) on derivative financial instruments		902			4,371			6,520			(6,001	)
Total Costs and Expenses		224,611			200,460			435,663			381,313

Operating Income		95,908			140,118			155,083			244,148

Other Income (Expense)
Other income		471			213			928			220
Interest expense		(27,008	)		(28,315	)		(53,526	)		(55,442	)
Total Other Expense		(26,537	)		(28,102	)		(52,598	)		(55,222	)

Income Before Income Taxes		69,371			112,016			102,485			188,926

Income Tax Expense		24,279			12,894			36,044			16,212

Net Income	$	45,092		$	99,122		$	66,441		$	172,714

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 December 31,						Six Months Ended December 31,
	2012			2011			2012			2011

Net Income	$	45,092		$	99,122		$	66,441		$	172,714

Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		1,400			(35,169	)		(36,341	)		165,240
Effective portion reclassified to earnings during the period		(10,797	)		(13,015	)		(21,337	)		(22,788	)
Total Other Comprehensive Income (Loss)		(9,397	)		(48,184	)		(57,678	)		142,452
Income Tax (Expense) Benefit		3,289			16,864			20,188			(49,858	)
Net Other Comprehensive Income (Loss)		(6,108	)		(31,320	)		(37,490	)		92,594

Comprehensive Income	$	38,984		$	67,802		$	28,951		$	265,308

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

	Six Months Ended
	December 31,
	2012			2011
	(In Thousands)
Cash Flows from Operating Activities
Net income	$	66,441		$	172,714
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Deferred income tax expense		36,045			16,363
Change in derivative financial instruments
Proceeds from sale of derivative instruments		61			65,529
Other – net		(13,885	)		(25,691	)
Accretion of asset retirement obligations		15,408			19,491
Depreciation, depletion and amortization		188,896			170,986
Amortization of debt issuance costs		3,798			3,705
Changes in operating assets and liabilities:
Accounts receivables		(7,930	)		(17,604	)
Prepaid expenses and other current assets		(7,862	)		(8,473	)
Asset retirement obligations		(24,809	)		(1,994	)
Accounts payable and other liabilities		11,067			(2,698	)
Net Cash Provided by Operating Activities		267,230			392,328

Cash Flows from Investing Activities
Acquisitions		(41,156	)		(6,177	)
Capital expenditures		(370,138	)		(236,112	)
Insurance payments received		—			6,472
Transfer to restricted cash		—			(1,028	)
Proceeds from the sale of properties		—			2,767
Other		(6	)		(74	)
Net Cash Used in Investing Activities		(411,300	)		(234,152	)

Cash Flows from Financing Activities
Proceeds from long-term debt		603,959			522,324
Payments on long-term debt		(481,158	)		(604,318	)
Advance to Energy XXI, Inc.		(911	)		(65,198	)
Contributions from (returns to) parent		(23,041	)		(10,161	)
Debt issuance costs and other		(173	)		(823	)
Net Cash Provided by (Used in) Financing Activities		98,676			(158,176	)

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	$	—		$	—

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012

(UNAUDITED)

Note 1 — Basis of Presentation

Nature of Operations. Energy XXI Gulf Coast, Inc. (“Energy XXI”), a Delaware corporation, was incorporated on February 7, 2006 and is a wholly-owned subsidiary of Energy XXI USA, Inc. (its “Parent”). Energy XXI (Bermuda) Limited (“Bermuda”), indirectly owns 100% of Parent. Energy XXI (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company, headquartered in Houston, Texas. We are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and offshore in the Gulf of Mexico.

Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income, stockholder’s equity or cash flows.

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

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.

Note 4 — Oil and Gas Properties

Oil and Gas Properties consist of the following (in thousands):

		December 31, 2012	June 30, 2012
Oil and natural gas properties
Proved properties	$	4,723,972	$	$4,375,984
Less: Accumulated depreciation, depletion, amortization and impairment		2,285,427		2,096,531
Proved properties		2,438,545		2,279,453
Unproved properties		498,305		418,760
Oil and natural gas properties	$	2,936,850	$	$2,698,213

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Note 5 — Long-Term Debt

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

	December 31, 2012		June 30, 2012
Revolving credit facility	$	123,928	$	—
9.25% Senior Notes due 2017		750,000		750,000
7.75% Senior Notes due 2019		250,000		250,000
Put premium financing		18,608		17,387
Total debt		1,142,536		1,017,387
Less current maturities		7,016		3,864
Total long-term debt	$	1,135,520	$	$1,013,523

Maturities of long-term debt as of December 31, 2012 are as follows (in thousands):


Twelve Months Ending December 31,
2013	$	7,016
2014		135,520
2015		—
2016		—
2017		750,000
Thereafter		250,000
Total	$	1,142,536

Revolving Credit Facility

We entered into the second amended and restated first lien credit agreement (“First Lien Credit Agreement”) in May 2011. This facility has a borrowing capacity of $925 million and matures December 31, 2014. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.25% to 3.00% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves.

Under the First Lien Credit Agreement, we are prohibited from paying dividends to Bermuda except that we may make payments to Bermuda of up to $25 million in aggregate for the purpose of Bermuda paying premiums or other payments associated with the early conversion of its preferred stock and we may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that Bermuda may pay dividends on its outstanding preferred stock. On October 4, 2011, we entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement. The First Amendment modified the First Lien Credit Agreement and includes the following: (a) approval for cash distributions of up to $100 million per calendar year to Bermuda, which can be used for various purposes, including stock buybacks, bond repurchases, and/or debt repayments, and is based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds, (b) approval of a cash distribution basket of up to an aggregate of $150 million, to be used for investments and other purposes based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds. Both distribution baskets are further limited by an amount equal to $70 million plus 50% of our Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter and (c) increased the amount of borrowing base availability that must be reserved to deal with potential effects from hurricanes during the period of July 1 to October 31 of each calendar year from $25 million to $50 million.

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

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

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.

As of December 31, 2012, 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 face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). We exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act of 1933, as amended (the “Securities Act”), on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

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

We have the right to redeem the 9.25% Senior Notes under various circumstances and are required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which 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 December 31, 2012 was $858.8 million based on quoted prices. The market for the 9.25% Senior Notes is not an active market; therefore, the fair value is classified within Level 2.

Guarantee of 9.25% Notes

We are the issuer of the 9.25% Notes which are fully and unconditionally guaranteed by Bermuda and each of its existing and future material domestic subsidiaries. Bermuda and its subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from paying dividends to Bermuda except that we may make payments to Bermuda of up to $25 million in aggregate for the purpose of Bermuda paying premiums or other payments associated with the early conversion of its preferred stock and we may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that Bermuda may pay dividends on our outstanding preferred stock.

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7.75% Senior Notes

On February 25, 2011, we issued $250 million face value of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). We exchanged the full $250 million aggregate principal of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (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 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 December 31, 2012 was $275 million based on quoted prices. The market for the 7.75% Senior Notes is not an active market; therefore, the fair value is classified within Level 2.

Guarantee of 7.75% Notes

We are the issuer of the 7.75% Notes which are fully and unconditionally guaranteed by Bermuda and each of its existing and future material domestic subsidiaries. Bermuda and its subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from paying dividends to Bermuda except that we may make payments to Bermuda of up to $25 million in aggregate for the purpose of Bermuda paying premiums or other payments associated with the early conversion of its preferred stock and we may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that Bermuda may pay dividends on our outstanding preferred stock.

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, 2012 and June 30, 2012, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $18.6 million and $17.4 million, respectively.

Interest Expense

For the three months and six months ended December 31, 2012 and 2011, interest expense consisted of the following (in thousands):

	Three Months Ended December 31,				Six Months Ended December 31,
	2012		2011		2012		2011

Revolving credit facility	$	2,676	$	2,270	$	4,855	$	5,090
9.25% Senior Notes due 2017		17,344		17,343		34,688		34,687
7.75% Senior Notes due 2019		4,844		4,844		9,688		9,688
Amortization of debt issue cost - Revolving credit facility		1,259		1,233		2,501		2,407
Amortization of debt issue cost – 9.25% Senior Notes due 2017		551		551		1,103		1,103
Amortization of debt issue cost – 7.75% Senior Notes due 2019		97		97		194		194
Derivative instruments financing and other		237		1,977		497		2,273
	$	27,008	$	28,315	$	53,526	$	55,442

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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 December 31, 2012 was $1.8 million.

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		6,443
Liabilities incurred		9,790
Liabilities settled		(24,809	)
Accretion expense		15,408
Total balance at December 31, 2012		308,247
Less current portion		29,815
Long-term balance at December 31, 2012	$	278,432

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.

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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 and received the following cash proceeds in the following quarters (in thousands):

Quarter Ended	Cash Proceeds
March 31, 2009	$	66,500
March 31, 2010		5,000
September 30, 2010		34,100
December 31, 2010		8,500
September 30, 2011		49,600
December 31, 2011		16,800
March 31, 2012		2,012
September 30, 2012		61
	$	182,573

These above monetized amounts were recorded in stockholders’ equity as part of other comprehensive income and are recognized in income over the contract life of the underlying hedge contracts. An additional $0.8 million monetization was captured in the September 30, 2011 quarter with the cash to be received when the underlying hedge contract settles during calendar year 2013.

Our future crude oil and natural gas revenue will be increased by the following amounts related to the monetized contracts referred to above (in thousands):

Quarter Ended	Cash (1)		Non-Cash (1)		Total
March 31, 2013	$	4,821	$	203	$	5,024
June 30, 2013		4,858		206		5,064
September 30, 2013		4,894		208		5,102
December 31, 2013		4,876		208		5,084
	$	19,449	$	825	$	20,274

(1) Cash represents the amounts received through December 31, 2012 as part of the monetization of certain hedge contracts. Non-cash represents monetized hedges in which the cash will be received when the underlying hedge contract settles in calendar year 2013.

As of December 31, 2012, we had the following contracts outstanding Asset (Liability) and Fair Value (Gain) Loss (in thousands):

	Crude Oil											Natural Gas
						Total										Total					Total
Period	Volume (MBbls)			Contract Price (1)		Asset (Liability)			Fair Value (Gain) Loss			Volume (MMBtu)		Contract Price (1)		Asset		Fair Value (Gain)			Asset (Liability)			Fair Value (Gain) Loss (2)
Crude Oil – WTI Collars
1/13 – 12/13		1,278			73.57/105.63		(395	)		256												(395	)		256
							(395	)		256												(395	)		256
Three-Way Collars
1/13 – 12/13		1,825			70/90/136.32		7,302			(1,352	)											7,302			(1,352	)
1/14 – 12/14		3,650			70/90/137.14		19,299			(5,790	)											19,299			(5,790	)
							26,601			(7,142	)											26,601			(7,142	)
Swaps
1/13 – 12/13		183			86.60		(1,204	)		188												(1,204	)		188
1/13 – 12/13		(183	)		88.20		913															913
							(291	)		188												(291	)		188
Crude Oil – Brent Collars
1/13 – 12/13		4,563			83.20/124.94		(1,185	)		1,708												(1,185	)		1,708
1/14 – 12/14		730			90/108.38		(1,327	)		815												(1,327	)		815
							(2,512	)		2,523												(2,512	)		2,523
Three-Way Collars
1/13 – 12/13		1,643			61.67/83.33/140.69		1,335						10,950		4.07/4.93/5.87		7,330		(4,765	)		8,665			(4,765	)
1/14 – 12/14		2,373			68.08/88.08/130.88		2,964			287												2,964			287
1/15 – 12/15		1,825			72/92/111.56		(2,820	)		1,734												(2,820	)		1,734
							1,479			2,021							7,330		(4,765	)		8,809			(2,744	)
Total (Gain) Loss on Derivatives						$	24,882		$	(2,154	)					$	7,330	$	(4,765	)	$	32,212		$	(6,919	)

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

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

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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
	December 31, 2012			June 30, 2012			December 31, 2012			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	$	40,948	Current	$	66,716	Current	$	26,851	Current	$	34,462
	Non-Current		79,280	Non-Current		103,462	Non-Current		61,165	Non-Current		58,229
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments	Current		-	Current		46	Current			Current		-
Total		$	120,228		$	170,224		$	88,016		$	92,691

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

	Three Months Ended December 31,				Six Months Ended December 31,
	2012		2011		2012		2011
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(4,870)	$	(3,283)	$	(9,370)	$	(433)
Natural gas sales		(5,039)		(9,571)		(10,540)		(19,400)
Total cash settlements		(9,909)		(12,854)		(19,910)		(19,833)
Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments		360		5,094		4,616		(1,674)
		360		5,094		4,616		(1,674)
Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market (gain) loss		697		(1,615)		1,973		(5,025)
Unrealized mark to market (gain) loss		(155)		892		(69)		698
Total (gain) loss on derivative financial instruments		902		4,371		6,520		(6,001)
Total gain	$	(9,007)	$	(8,483)	$	(13,390)	$	(25,834)

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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, 2012
Commodity Derivative Instruments	$	6,108
Revenues			$	(7,018)
(Gain) loss on derivative financial instruments					$	360
Total	$	6,108	$	(7,018)	$	360
Three Months Ended December 31, 2011
Commodity Derivative Instruments	$	31,320
Revenues			$	(8,460)
(Gain) loss on derivative financial instruments					$	5,094
Total	$	31,320	$	(8,460)	$	5,094

Six Months Ended December 31, 2012
Commodity Derivative Instruments	$	37,490
Revenues			$	(13,869)
(Gain) loss on derivative financial instruments					$	4,616
Total	$	37,490	$	(13,869)	$	4,616
Six Months Ended December 31, 2011
Commodity Derivative Instruments	$	(92,594)
Revenues			$	(14,812)
(Gain) loss on derivative financial instruments					$	(1,674)
Total	$	(92,594)	$	(14,812)	$	(1,674)

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $26.4 million ($17.1 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 December 31, 2012, 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 $82.3 million (related to certain state of Louisiana tax attributes and other property matters), and have made no adjustments to this allowance in the current quarter. 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 third quarter of fiscal year 2013. We are a party to an intercompany agreement whereby we would be responsible for funding consolidated US 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 six months ended December 31, 2012 we returned capital of $23.0 million to our Parent and during the six months ended December 31, 2011, we returned capital of $10.2 million 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 $0.5 million and 0.9 million for the three and six months ended December 31, 2012, respectively. Interest on the note receivable amounted to approximately $0.2 million for the three and six months ended December 31, 2011. 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, 2012.

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 six months ended December 31, 2012 were approximately $17.7 million and $39.3 million, respectively, and cost of these services for the three months and six months ended December 31, 2011 were approximately $20.7 million, $38.8 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 December 31,				Six Months Ended December 31,
	2012		2011		2012		2011
Cash paid for interest	$	47,069	$	46,768	$	47,439	$	52,023

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


	Three Months Ended December 31,				Six Months Ended December 31,
	2012		2011		2012		2011
Financing of insurance premiums	$	11,853	$	8,517	$	20,387	$	9,196
Additions to property and equipment by recognizing asset retirement obligations		6,240		794		9,790		1,338

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 $225.5 million in letters of credit and $44.4 million of performance bonds outstanding as of December 31, 2012.

Drilling Rig Commitments. As of December 31, 2012, we have entered into five drilling rig commitments:

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

2) July 3, 2012 to May 15, 2013 at $49,000 per day

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

4) September 4, 2012 to March 4, 2013 at $120,000 per day

5) October 2, 2012 to February 28, 2013 at $90,000 per day

At December 31, 2012, future minimum commitments under these contracts totaled $80.3 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 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 2 financial instruments (in thousands):

	Level 2
	December 31,		June 30,
	2012		2012
Assets:
Oil and natural gas derivatives	$	120,228	$	170,955
Liabilities:
Oil and natural gas derivatives	$	88,016	$	92,962

Note 14 — Prepayments and Accrued Liabilities

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

	December 31,		June 30,
	2012		2012

Prepaid expenses and other current assets
Advances to joint interest partners	$	17,794	$	12,966
Insurance		13,609		30,162
Inventory		4,311		4,849
Royalty deposit		2,620		2,443
Other		244		683
Total prepaid expenses and other current assets	$	38,578	$	51,103

Accrued liabilities
Advances from joint interest partners	$	10,659	$	301
Interest		5,820		3,721
Accrued hedge payable		312		136
Undistributed oil and gas proceeds		29,518		54,484
Other		829		1,453
Total accrued liabilities	$	47,138	$	60,095

Note 15 — Subsequent Event

On January 17, 2013, we closed on an acquisition to acquire certain onshore Louisiana interests in Laphroaig field from McMoRan Oil and Gas, LLC for a total cash consideration of $80 million. This acquisition is effective January 1, 2013. We previously held an 18.75% working interest in this field, and post-acquisition we will hold a 56.25% working interest. This acquisition adds 2,000 BOE/d of production from the field’s two producing wells of which we will now be the operator. This acquisition will be accounted using the purchase method of accounting. We are presently evaluating the purchase price allocation, which is subject to customary closing adjustments.

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Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - February 12, 2013

Attached files

Energy XXI Ltd Reports