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, 2011

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011

C O N T E N T S

	Page

Consolidated Balance Sheets		3

Consolidated Statements of Operations		4

Consolidated Statements of Cash Flows		5

Notes to Consolidated Financial Statements		6

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	December 31,			June 30,
	2011			2011
ASSETS	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	—
Restricted cash		1,028			—
Receivables:
Oil and natural gas sales		141,314			126,194
Joint interest billings		2,814			4,526
Insurance and other		2,454			1,303
Prepaid expenses and other current assets		41,802			44,470
Royalty deposit		2,443			1,959
Derivative financial instruments		5,592			22
TOTAL CURRENT ASSETS		197,447			178,474

Oil and gas properties – full cost method of accounting, including $516.6 million and $467.3 million unevaluated properties at December 31, 2011 and June 30, 2011, respectively, net of accumulated depreciation, depletion, amortization and impairment		2,608,737			2,545,336
Other assets
Deferred taxes		—			51,827
Note receivable from Energy XXI, Inc.		65,198			—
Derivative financial instruments		9,963			—
Debt issuance costs, net of accumulated amortization		30,635			33,479

TOTAL ASSETS	$	2,911,980		$	2,809,116

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	150,282		$	163,723
Accrued liabilities		68,146			53,089
Notes payable		9,196			19,853
Asset retirement obligations		25,379			19,624
Derivative financial instruments		25,352			50,259
Current maturities of long-term debt		2,238			3,798
TOTAL CURRENT LIABILITIES		280,593			310,346
Long-term debt, less current maturities		1,028,478			1,108,912
Asset retirement obligations		316,698			303,618
Deferred taxes		14,397			—
Derivative financial instruments		951			70,524
TOTAL LIABILITIES		1,641,117			1,793,400
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, 2011 and June 30, 2011		1			1
Additional paid-in capital		1,446,356			1,456,517
Accumulated deficit		(199,604	)		(372,318	)
Accumulated other comprehensive income (loss), net of
income taxes		24,110			(68,484	)
TOTAL STOCKHOLDER’S EQUITY		1,270,863			1,015,716

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	2,911,980		$	2,809,116

See accompanying Notes to Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Six Months Ended
	December 31,						December 31,
	2011			2010			2011			2010
	(In Thousands)
Revenues
Oil sales	$	309,347		$	146,539		$	556,264		$	262,369
Natural gas sales		31,231			27,414			69,197			55,584
Total Revenues		340,578			173,953			625,461			317,953

Costs and Expenses
Lease operating		74,134			44,446			145,167			88,599
Production taxes		1,174			716			3,348			1,410
Gathering and transportation		3,395			801			9,548			822
Depreciation, depletion and amortization		86,878			62,315			170,986			115,756
Accretion of asset retirement obligations		9,803			6,348			19,491			12,322
General and administrative		20,705			14,368			38,774			32,016
Loss (gain) on derivative financial instruments		4,371			(1,638	)		(6,001	)		(2,776	)
Total Costs and Expenses		200,460			127,356			381,313			248,149

Operating Income		140,118			46,597			244,148			69,804

Other Income (Expense)
Bridge loan commitment fees		—			(4,500	)		—			(4,500	)
Loss on retirement of debt		—			(5,184	)		—			(5,184	)
Other income		213			92			220			102
Interest expense		(28,315	)		(22,068	)		(55,442	)		(43,534	)
Total Other Expense		(28,102	)		(31,660	)		(55,222	)		(53,116	)

Income Before Income Taxes		112,016			14,937			188,926			16,688

Income Tax Expense		12,894			—			16,212			—

Net Income	$	99,122		$	14,937		$	172,714		$	16,688

See accompanying Notes to Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

	Six Months Ended
	December 31,
	2011			2010
	(In Thousands)
Cash Flows from Operating Activities
Net income	$	172,714		$	16,688
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Deferred income tax expense		16,363			—
Change in derivative financial instruments
Proceeds from sale of derivative instruments		65,529			42,577
Other – net		(25,691	)		(16,214	)
Accretion of asset retirement obligations		19,491			12,322
Depreciation, depletion and amortization		170,986			115,756
Payment of interest in-kind		—			2,225
Amortization of deferred gain on debt and debt discount and premium		—			(43,132	)
Amortization of debt issuance costs		3,705			4,254
Changes in operating assets and liabilities:
Accounts receivables		(17,604	)		(40,800	)
Prepaid expenses and other current assets		(8,473	)		(1,283	)
Asset retirement obligations		(1,994	)		(34,618	)
Accounts payable and other liabilities		(2,698	)		21,343
Net Cash Provided by Operating Activities		392,328			79,118

Cash Flows from Investing Activities
Acquisitions		(6,177	)		(1,013,011	)
Capital expenditures		(236,112	)		(127,804	)
Insurance payments received		6,472			—
Transfer to restricted cash		(1,028	)		—
Proceeds from the sale of properties		2,767			400
Other		(74	)		—
Net Cash Used in Investing Activities		(234,152	)		(1,140,415	)

Cash Flows from Financing Activities
Proceeds from long-term debt		522,324			1,160,000
Payments on long-term debt		(604,318	)		(586,767	)
Advance to Energy XXI, Inc.		(65,198	)		—
Contributions from (returns to) parent		(10,161	)		511,907
Debt issuance costs and other		(823	)		(30,259	)
Net Cash Provided by (Used in) Financing Activities		(158,176	)		1,054,881

Net Decrease in Cash and Cash Equivalents		—			(6,416	)

Cash and Cash Equivalents, beginning of period		—			6,416

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

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011

(UNAUDITED)

Note 1 — Basis of Presentation

Nature of Operations. Energy XXI Gulf Coast, Inc. (“Energy XXI”), a Delaware corporation, was incorporated on February 7, 2006 and is a wholly-owned subsidiary of Energy XXI USA, Inc. (its “Parent”). 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 Texas and offshore in the Gulf of Mexico.

Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), 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, 2011.

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

We disclose the existence and potential effect of accounting standards issued but not yet adopted by us or recently adopted by us with respect to accounting standards that may have an impact on us in the future.

Presentation of Comprehensive Income. The FASB has issued new guidance on the presentation of comprehensive income . This new guidance allows an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. This guidance eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. The new guidance does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. Components of comprehensive income are stated net of income tax at 35%, subject to evaluations for the need for a valuation allowance against any resulting deferred tax asset(s).

This new guidance will be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted.

Note 3 — Acquisitions and Dispositions

ExxonMobil Acquisition

On December 17, 2010, we closed on the acquisition of certain shallow-water Gulf of Mexico shelf oil and natural gas interests (the”ExxonMobil Properties”) from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”). The ExxonMobil Acquisition was funded through a combination of cash on hand, including proceeds from Bermuda’s common and preferred equity offerings, borrowings under our revolving credit facility and proceeds from our $750 million private placement of 9.25% Senior Notes.

Pursuant to the Purchase and Sale Agreement (the “PSA”), ExxonMobil reserved a 5% overriding royalty interest in the ExxonMobil Properties for production from depths below approximately 16,000 feet. In addition, the PSA required us to post a $225 million letter of credit, which we posted under our revolving credit facility, in favor of ExxonMobil to guarantee our obligation to plug and abandon the ExxonMobil Properties in the future.

The ExxonMobil Acquisition 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 final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 17, 2010 ( in thousands ):

	December 17, 2010 (As initially reported)			Measurement period adjustment		December 17, 2010 (As adjusted)
Oil and natural gas properties – evaluated	$	926,422		$	—	$	926,422
Oil and natural gas properties – unevaluated		289,711			—		289,711
Net working capital*		101			577		678
Asset retirement obligations		(204,512	)		—		(204,512	)
Cash paid	$	1,011,722		$	577	$	1,012,299

* The above estimated fair values of assets acquired and liabilities assumed are based on the information that was available as of the acquisition date to estimate the fair value of the assets acquired and liabilities assumed. As of December 31, 2011, the Company’s measurement period adjustments are complete.

The following amounts of the ExxonMobil Properties’ revenue and earnings are included in our consolidated statement of operations for the six months ended December 31, 2011 and the summarized unaudited pro forma financial information for the six months ended December 31, 2010 assumes that the ExxonMobil Acquisition had occurred on July 1, 2010. These unaudited pro forma financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if we had completed the acquisition as of the earlier date or the results that will be attained in the future (in thousands):

	Revenue		Earnings (1)
ExxonMobil Acquisition properties from July 1, 2011 through December 31, 2011	$	268,355	$	193,214
ExxonMobil Acquisitions properties
Supplemental pro forma for July 1, 2010 through December 31, 2010		489,687		353,717

(1) Earnings includes revenue less production costs.

Sale of Certain Onshore Properties

In June 2011, we closed on the sale of certain onshore oil and natural gas properties for cash consideration of $39.6 million. Revenues and expenses related to the sold properties have been included in our results of operations through the closing dates. The proceeds were recorded as a reduction to our oil and gas properties with no gain or loss being recognized.

Below is a summary of net reduction to the full cost pool related to the sale (in thousands):

Cash received	$	39,625
Reduction of asset retirement obligation related to properties		16,626
Net revenues from June 1, 2011 through closing date		(1,630	)
Adjustment to gas imbalances related to properties		36
Net reduction to the full cost pool	$	54,657

Note 4 — Oil and Gas Properties

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

		December 31, 2011	June 30, 2011
Oil and natural gas properties
Proved properties	$	3,995,418	$	3,810,293
Less: Accumulated depreciation, depletion, amortization and impairment		1,903,236		1,732,250
Proved properties		2,092,182		2,078,043
Unproved properties		516,555		467,293
Oil and natural gas properties	$	2,608,737	$	2,545,336

Note 5 — Long-Term Debt

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

	December 31, 2011		June 30, 2011
Revolving credit facility	$	28,478	$	107,784
9.25% Senior Notes due 2017		750,000		750,000
7.75% Senior Notes due 2019		250,000		250,000
Put premium financing		2,238		4,926
Total debt		1,030,716		1,112,710
Less current maturities		2,238		3,798
Total long-term debt	$	1,028,478	$	1,108,912

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

Twelve Months Ending December 31,
2012	$	2,238
2013		—
2014		28,478
2015		—
2016		—
Thereafter		1,000,000
Total	$	1,030,716

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. As at December 31, 2011, the current borrowing base was $750 million, which was unanimously reaffirmed by the lenders on September 14, 2011. 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.

We are prohibited from paying dividends to Bermuda except that we may make payments to it of up to $25 million in aggregate (including those in the aggregate total amount of $11,082,156 made to date) for the purpose of 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 it 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 which provided for increased flexibility to pay dividends or make loans from us to Bermuda and/or its other subsidiaries. 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, 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, and (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.

The First Amendment also increased the amount of borrowing base availability that must be reserved to deal with potential effects from hurricanes during the period of July 1st to October 31st of each calendar year from $25 million to $50 million.

The First Lien Credit Agreement 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 its ability to declare and pay dividends or other payments, its ability to incur debt, changes in control, its ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

As of December 31, 2011, 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 was 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 in connection with the issuance of the 9.25% Old Senior Notes which have been capitalized and will be amortized over the life of the 9.25% Senior Notes.

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

The 9.25% Senior Notes 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 is prohibited from declaring or paying any dividend in excess of $70 million plus 50% of our consolidated net income for the period from October 1, 2010, subject to certain other adjustments and exceptions.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of December 31, 2011 was $818.4 million.

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 in connection with the issuance of the 7.75% Old Senior Notes which have been capitalized and will be amortized over the life of the 7.75% Senior Notes.

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

The 7.75% Senior Notes are fully and unconditionally guaranteed by Bermuda and each of our existing and future material domestic subsidiaries. We are the issuer of the 7.75% Senior Notes which are fully and unconditionally guaranteed by Bermuda. Bermuda and its subsidiaries, other than us, have no significant independent assets or operations. We are prohibited from declaring or paying any dividend in excess of $70 million plus 50% of our consolidated net income for the period from October 1, 2010, subject to certain other adjustments and exceptions.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of December 31, 2011 was $257.5 million.

Put Premium Financing

We finance premiums on puts that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Put premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The put premium financing is structured to mature when the put settles so that we realize the value net of put premium financing. As of December 31, 2011 and June 30, 2011, our outstanding put premium financing totaled $2.2 million and $4.9 million, respectively.

Interest Expense

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

	Three Months Ended December 31,					Six Months Ended December 31,
	2011		2010			2011		2010
Revolving credit facility	$	2,270	$	1,456		$	5,090	$	2,897
9.25% Senior Notes due 2017		17,343		2,505			34,687		2,505
7.75% Senior Notes due 2019		4,844		—			9,688		—
10% Senior Notes due 2013		—		6,912			—		13,825
16% Second Lien Notes due 2014		—		11,286			—		24,967
Amortization of debt issue cost – Revolving credit facility		1,233		1,381			2,407		2,525
Amortization of debt issue cost – 10% Senior Notes due 2013		—		589			—		1,178
Amortization of debt issue cost – 16% Second Lien Notes due 2014		—		25			—		54
Amortization of debt issue cost – 9.25% Senior Notes due 2017		551		92			1,103		92
Amortization of debt issue cost – 7.75% Senior Notes due 2019		97		—			194		—
Discount amortization – 16% Second Lien Notes due 2014 (Private Placement)		—		(3,098	)		—		(6,889	)
Premium amortization – 16% Second Lien Notes due 2014 (Exchange Offer)		—		852			—		1,894
Put premium financing and other		87		68			383		486
Settlement of Lehman Brothers liability		1,890		—			1,890		—
	$	28,315	$	22,068		$	55,442	$	43,534

Bridge Loan Commitment Fee

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

Note 6 — Notes Payable

In May 2011, we entered into a note with Bank Direct Capital Finance, LLC to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.93%. The note amortizes over ten months. The balance outstanding as of December 31, 2011 and June 30, 2011 was $6.6 million and $19.9 million, respectively.

In July 2011, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note is for a total face amount of $6.3 million and bears interest at an annual rate of 1.93%. The note amortizes over the remaining term of the insurance, which matures May 1, 2012. The balance outstanding as of December 31, 2011 was $2.6 million.

Note 7 — Asset Retirement Obligations

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

Balance at June 30, 2011	$	323,242
Liabilities incurred		1,338
Liabilities settled		(1,994	)
Accretion expense		19,491
Total balance at December 31, 2011		342,077
Less current portion		25,379
Long-term balance at December 31, 2011	$	316,698

Note 8 — Derivative Financial Instruments

We enter into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. The Company designates a majority of its 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 the Company discontinues 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 have utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the 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, the Company began utilizing ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By modifying our hedge portfolio to include Brent benchmarks for crude hedging, we aim to more appropriately manage our exposure and manage our price risk.

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

We have monetized certain hedge positions 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
	$	180,500

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 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 Ending	Cash (1)		Non-Cash (1)		Total
March 31, 2012	$	10,546	$	—	$	10,546
June 30, 2012		11,023		—		11,023
September 30, 2012		8,532		—		8,532
December 31, 2012		8,040		—		8,040
Thereafter		19,449		825		20,274
	$	57,590	$	825	$	58,415

(1) Cash represents the amounts received as of December 31, 2011 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 2013.

As of December 31, 2011, 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 (MMMBtu)	Contract Price (1)		Asset (Liability)		Fair Value (Gain) Loss			Asset (Liability)			Fair (Gain) Loss (2)
WTI Commodity Collars
1/12 – 12/12		2,818	$	72.60/$100.19		$	(18,797	)	$	12,218		1,840	$	4.50/$5.35	$	2,158	$	(1,403	)	$	(16,639	)	$	10,815
1/13 – 12/13		1,278		73.57/105.63			(4,203	)		2,732											(4,203	)		2,732
							(23,000	)		14,950						2,158		(1,403	)		(20,842	)		13,547
Brent Commodity Collars
1/12 – 12/12		1,830		87.00/114.24			(4,567	)		2,959											(4,567	)		2,959
1/13 – 12/13		3,103		80.00/126.78			2,602														2,602
							(1,965	)		2,959											(1,965	)		2,959
Three-Way Collars
1/12 – 12/12		4,465		66.93/86.93/133.55			(2,521	)		3,283		5,520		4.07/4.93/5.87		3,968		(2,580	)		1,447			703
1/13 – 12/13		1,643		61.67/83.33/140.69			2,906			(123	)	10,950		4.07/4.93/5.87		5,719		(3,717	)		8,625			(3,840	)
1/14 – 12/14		1,095		65.00/85.00/140.00			1,987														1,987
							2,372			3,160						9,687		(6,297	)		12,059			(3,137	)
Total (Gain) Loss on Derivatives						$	(22,593	)	$	21,069					$	11,845	$	(7,700	)	$	(10,748	)	$	13,369

[Missing Graphic Reference]

(1)

The contract price is weighted-averaged by contract volume.

(2)

The loss on derivative contracts is net of applicable income taxes.

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

	Asset Derivative Instruments						Liability Derivative Instruments
	As of December 31, 2011			As of June 30, 2011			As of December 31, 2011			As of June 30, 2011
	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	$	43,165	Current	$	6,048	Current	$	62,925	Current	$	58,593
	Non-Current		68,848	Non-Current		1,248	Non-Current		59,836	Non-Current		72,719
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments	Current		—	Current		2,310	Current		—	Current		3
	Non-Current		—	Non-Current		948	Non-Current		—	Non-Current		—
Total		$	112,013		$	10,554		$	122,761		$	131,315

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,
Location of (Gain) Loss in Income Statement	2011			2010			2011			2010
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(3,283	)	$	9,734		$	(433	)	$	12,167
Natural gas sales		(9,571	)		(9,113	)		(19,400	)		(17,839	)
Total cash settlements		(12,854	)		621			(19,833	)		(5,672	)
Commodity Derivative Instruments designated as hedging instruments:
Loss (gain) on derivative financial instruments Ineffective portion of commodity derivative instruments		5,094			(266	)		(1,674	)		215
Commodity Derivative Instruments not designated as hedging instruments:
Loss (gain) on derivative financial instruments Realized mark to market gain		(1,615	)		(1,840	)		(5,025	)		(3,226	)
Loss (gain) on derivative financial instruments Unrealized mark to market loss		892			468			698			235
Total loss (gain) on derivative financial instruments		4,371			(1,638	)		(6,001	)		(2,776	)
Total gain	$	(8,483	)	$	(1,017	)	$	(25,834	)	$	(8,448	)

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

	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)
Location of (Gain) Loss	2011		2010			2011			2010			2011		2010
Three Months Ended December 31,
Commodity Derivative Instruments	$	31,320	$	(57,880)		$	—		$	—		$	—	$	—
Revenues		—		—			(8,460)			(478)			—		—
Loss (gain) on derivative financial instruments		—		—			—			—			5,094		(266)
Total	$	31,320	$	(57,880	)	$	(8,460	)	$	(478	)	$	5,094	$	(266	)
Six Months Ended December 31,
Commodity Derivative Instruments	$	(92,594)	$	(68,123)		$	—		$	—		$	—	$	—
Revenues		—		—			(14,812)			(366)			—		—
Loss (gain) on derivative financial instruments		—		—			—			—			(1,674)		215
Total	$	(92,594)	$	(68,123)		$	(14,812)		$	(366)		$	(1,674)	$	215

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

Comprehensive income includes net income and certain items recorded directly in Stockholders’ equity and classified as accumulated other comprehensive income. Comprehensive income (loss) was calculated as follows (in thousands):

	Three Months Ended December 31,							Six Months Ended December 31,
	2011			2010				2011				2010

Net income	$	99,122			$	14,937			$	172,714			$	16,688
Other comprehensive income (loss), net of tax:
Oil and gas cash flow hedges
Unrealized change in fair value including monetized hedges		(22,860	)			(57,402	)			107,406				(67,757	)
Reclassified to earnings during the period		(8,460	)			(478	)			(14,812	)			(366	)
Other comprehensive income (loss), net of tax:		(31,320	)			(57,880	)			92,594				(68,123	)
Comprehensive income (loss)	$	67,802			$	(42,943	)		$	265,308			$	(51,435	)

The amount expected to be reclassified to income in the next 12 months is a gain of $15.9 million on our commodity hedges.

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. As such, the income tax amounts presented herein have been presented by applying the provisions of ASC 740 to us in this manner.

During the year ended June 30, 2009, we incurred a significant impairment loss related to our oil and gas properties due to the steep decline in global energy prices over that same time period. As a result of this impairment, we were in a position of cumulative reporting losses for the preceding reporting periods. The volatility of energy prices since has been problematic and not readily determinable by our management. Under these circumstances, it has been management’s opinion that the realization of our tax attributes beyond expected current-year taxable income (including the reversal of existing taxable temporary differences and the resolution of certain hedging activity) does not reach the “more likely than not” criteria under ASC 740. As a result, during the year ended June 30, 2009, we established a valuation allowance of $175.0 million, but have subsequently reduced the valuation allowance due to the presence of actual earnings reported in quarters since establishment of the allowance. If current indications of pre-tax earnings for the year prove to be correct, we will release approximately $90 million of our remaining valuation allowance during this fiscal year (which has been reflected in the estimated annual effective tax rate reflected herein). While the Company has not made significant income tax payments in recent years, in light of future expected income, estimated tax payments in subsequent quarters may be required in amounts yet to be determined in accordance with the applicable federal income tax provisions related to required corporate estimated tax payments.

Note 10 — Related Party Transactions

During the six months ended December 31, 2011 we returned capital of $75.2 million to our Parent and during the six months ended December 31, 2010, our Parent contributed capital of $511.9 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 $0.2 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, 2011.

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, 2011 and 2010 was approximately $20.7 million, $38.8 million, $14.4 million and $32.0 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,
	2011		2010		2011		2010
Cash paid for interest	$	46,768	$	40,146	$	52,023	$	42,276

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

	Three Months Ended December 31,				Six Months Ended December 31,
	2011		2010		2011		2010
Financing of insurance premiums	$	8,517	$	6,534	$	9,196	$	6,574
Additions to property and equipment by recognizing asset retirement obligations		794		206,117		1,338		207,167

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 financial position or results of operations.

Letters of Credit and Performance Bonds. We had $231.5 million in letters of credit and $25.1 million of performance bonds outstanding as of December 31, 2011.

Drilling Rig Commitments. As of December 31, 2011, we have entered into four drilling rig commitments, the first of which commenced on July 3, 2011 at $42,500 per day for one well until well completion. The second commitment commenced on October 1, 2011 at $65,000 per day for six months. The third commenced on November 4, 2011 at $47,800 per day for four wells until well completion with options to do additional work. The last one commenced on December 10, 2011 at $44,500 per day for one well until well completion. Since the preceding commitments are not finished and extend past December 31, 2011, the commitment amounts cannot be calculated since the well completion dates are not known.

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 as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. In addition, for collars, we estimate the option values using an option pricing model which takes into account market volatility, market prices and contract terms. 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.

Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments. Our natural gas and oil derivatives are classified as described below:

•

Level 2 instruments’ fair values are based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets). Included in this level are our natural gas and oil derivatives whose fair values are based on commodity pricing data obtained from independent pricing sources.

The fair value of our financial instruments was as follow (in thousands):

	Level 2
	As of December 31, 2011		As of June 30, 2011
Assets:
Oil and Natural Gas Derivatives	$	15,555	$	22
Liabilities:
Oil and Natural Gas Derivatives		26,303		120,783

Note 14 — Prepayments and Accrued Liabilities

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

	December 31, 2011		June 30, 2011
Prepaid expenses and other current assets
Advances to joint interest partners	$	22,774	$	14,696
Insurance		12,159		22,972
Inventory		6,207		6,305
Other		662		497
Total prepaid expenses and other current assets	$	41,802	$	44,470
Accrued liabilities
Advances from joint interest partners	$	1,322	$	437
Interest		3,736		5,806
Accrued hedge payable		11,425		14,095
Undistributed oil and gas proceeds		50,449		31,880
Other		1,214		871
Total accrued liabilities	$	68,146	$	53,089

Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - February 15, 2012

Attached files

Energy XXI Ltd Reports