Exhibit 99.1

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

C O N T E N T S

	Page
Consolidated Balance Sheets		3
Consolidated Statements of Income		4
Consolidated Statements of Cash Flows		5
Notes to Consolidated Financial Statements		6

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	September 30,		June 30,
	2008		2008
	(Unaudited)
Assets
Current Assets
Cash and cash equivalents	$	6,347	$	2,664
Accounts receivable
Oil and natural gas sales		56,949		116,678
Joint interest billings		28,123		21,322
Insurance and other		4,804		3,585
Prepaid expenses and other current assets		40,040		12,420
Royalty deposits		3,249		4,548
Deferred income taxes		481		88,340
Derivative financial instruments		18,303		2,179
Total Current Assets		158,296		251,736
Property and Equipment
Oil and Gas Properties – full cost method of accounting, net of accumulated depreciation, depletion, and amortization		1,587,708		1,561,276
Other Assets
Derivative financial instruments		4,298		3,747
Deferred income taxes		2,163		35,850
Debt issuance costs, net of accumulated amortization		16,377		17,388
Total Other Assets		22,838		56,985
Total Assets	$	1,768,842	$	1,869,997

Liabilities and Stockholder’s Equity
Current Liabilities
Accounts payable	$	88,914		$	106,173
Note payable		12,566			-
Accrued liabilities		93,939			82,983
Derivative financial instruments		47,213			245,626
Current maturities of long-term debt		8,254			7,093
Total Current Liabilities		250,886			441,875
Long-term debt, less current maturities		938,125			944,604
Asset retirement obligations		79,482			81,097
Derivative financial instruments		48,316			190,781
Total Liabilities		1,316,809			1,658,357
Commitments and Contingencies (Note 10)
Stockholder’s Equity
Common stock, $0.01 par value, 1,000,000 shares
authorized and 100,000 issued and outstanding
at September 30, 2008 and June 30, 2008		1			1
Additional paid-in capital		450,216			436,301
Retained earnings		55,447			60,348
Accumulated other comprehensive loss, net of tax benefit		(53,631	)		(285,010	)
Total Stockholder’s Equity		452,033			261,640
Total Liabilities and Stockholder’s Equity	$	1,768,842		$	1,869,997

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands)

(Unaudited)

	Three Months Ended
	September 30,
	2008			2007
Revenues
Oil sales	$	82,062		$	86,723
Natural gas sales		37,682			52,323
Total Revenues		119,744			139,046
Costs and Expenses
Lease operating expense		34,998			30,002
Production taxes		2,036			1,960
Depreciation, depletion and amortization		61,712			69,445
Accretion of asset retirement obligation		2,461			1,755
General and administrative expense		5,310			5,513
Loss (gain) on derivative financial instruments		(1,864	)		1,679
Total Costs and Expenses		104,653			110,354
Operating Income		15,091			28,692
Other Income (Expense)
Interest income		231			456
Interest expense		(23,265	)		(25,803	)
Total Other Income (Expense)		(23,034	)		(25,347	)
Income (Loss) Before Income Taxes		(7,943	)		3,345
Income Tax Expense (Benefit)		(3,042	)		1,147
Net Income (Loss)	$	(4,901	)	$	2,198

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(In Thousands)

(Unaudited)

	Three Months Ended
	September 30,
	2008			2007
Cash Flows from Operating Activities
Net income (loss)	$	(4,901	)	$	2,198
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Deferred income tax expense		(3,042	)		1,147
Change in derivative financial instruments		(1,342	)		(22	)
Accretion of asset retirement obligations		2,461			1,755
Depreciation, Depletion and amortization		61,712			69,445
Write-off and amortization of debt issuance costs		1,012			1,068
Changes in operating assets and liabilities:
Accounts receivables		54,077			(19,335	)
Prepaid expenses and other current assets		(26,321	)		(29,152	)
Accounts payable and other liabilities		6,176			50,781
Net Cash Provided by Operating Activities		89,832			77,885
Cash Flows from Investing Activities
Acquisitions		-			(3,521	)
Capital expenditures		(92,128	)		(78,361	)
Other-net		(84	)		28
Net Cash Used in Investing Activities		(92,212	)		(81,854	)
Cash Flows from Financing Activities
Proceeds from long-term debt		142,185			20,000
Payments on long-term debt		(148,000	)		(20,000	)
Advances from (to) affiliates		13,915			(2,446	)
Payments on put financing and other		(2,037	)		(1,074	)
Net Cash Provided by (Used in) Financing Activities		6,063			(3,520	)
Net Increase (Decrease) in Cash and Cash Equivalents		3,683			(7,489	)
Cash and Cash Equivalents, beginning of period		2,664			15,265
Cash and Cash Equivalents, end of period	$	6,347		$	7,776

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(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 (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 period 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 consolidated financial statements for the periods presented herein are unaudited and do not contain all information required by generally accepted accounting principles (“GAAP”) to be included in a full set of financial statements.  In the opinion of management, all material adjustments necessary to present fairly the results of operations have been included.  All such adjustments are of a normal, recurring nature.  The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.  These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements for the year ended June 30, 2008.

Use of Estimates.  The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the 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.  While we believe that the estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Note 2 – Recent Accounting Pronouncements

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

The Hierarchy of Generally Accepted Accounting Principles.  In May 2008, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards (“SFAS”) No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. The FASB believes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. We do not expect the adoption of SFAS No. 162 to have a material effect on our results of operations or financial position.

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Disclosures about Derivative Instruments and Hedging Activities.  In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The use and complexity of derivative instruments and hedging activities have increased significantly over the past several years. Many have expressed concerns that the existing disclosure requirements in SFAS No. 133 do not provide adequate information about how derivative and hedging activities affect an entity’s financial position, financial performance, and cash flows. Accordingly, SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting.  SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. SFAS No. 161 encourages, but does not require, comparative disclosures for earlier periods at initial adoption.  We are currently evaluating the impact that SFAS No. 161 may have on our disclosures.

Accounting for Business Combinations.  In December 2007, the FASB issued SFAS No. 141R, Business Combinations (“SFAS 141R”), which replaces SFAS No. 141, Business Combinations. SFAS 141R establishes principles and requirements for determining how an enterprise recognizes and measures the fair value of certain assets and liabilities acquired in a business combination, including non-controlling interests, contingent consideration, and certain acquired contingencies. SFAS 141R also requires acquisition-related transaction expenses and restructuring costs be expensed as incurred rather than capitalized as a component of the business combination. SFAS 141R will be applicable prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS 141R would have an impact on accounting for any businesses acquired after the date of adoption.

Note 3 – Acquisitions

Partnership

In July 2007, our Parent acquired a 49.5% limited partnership interest in the Castex Energy 2007, L.P. (the “Partnership”). The Partnership was formed on May 30, 2007 with Castex Energy, Inc. as general partner and Castex Energy 2005, L.P. as the limited partner. Revenue and expenses are allocated 1% to the general partner and 99% to the limited partners. The Partnership was formed to acquire certain onshore southern Louisiana assets from EPL of Louisiana, L.L.C. effective April 1, 2007 for consideration of $71.7 million.

The Partnership financed the acquisition with a $73 million credit agreement with Lehman Brothers Inc. acting as sole arranger and Lehman Commercial Paper Inc. as administrative agent. The credit agreement required the Partnership to enter into certain derivative transactions and under certain circumstances requires additional capital contributions by the partners of up to $15 million.

The following table presents the allocation of our Parent’s 49.5% interest of the assets acquired and liabilities assumed, based on their fair values on July 1, 2007 (in thousands):

Net working capital	$	5,678
Other assets		510
Oil and natural gas properties		29,947
Total Assets	$	36,135
Long-term debt	$	36,135

On November 30, 2007, our Parent’s proportionate share of the Partnership assets and liabilities were distributed to it.  On December 1, 2007, our Parent transferred to us their distributed share of the Partnership’s net oil and gas properties at book value, $24,448,000.

East Cameron Field

In July 2007, we acquired from ExxonMobil for $3.5 million plus assumption of asset retirement obligations, their approximately 30 percent interest in the East Cameron 334/335 Field in the Gulf of Mexico.  We had previously acquired an interest in this field from Pogo Producing Company.

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Note 4 – Oil and Gas Properties

Oil and gas properties consist of the following (in thousands):

	September 30, 2008		June 30, 2008
Oil and gas properties
Proved properties	$	1,914,190	$	1,810,814
Less: Accumulated depreciation, depletion and amortization		532.431		465,219
Proved properties – net		1,381,759		1,345,595
Unproved properties		205,949		215,681
Oil and gas properties – net	$	1,587,708	$	1,561,276

Note 5 – Long-term Debt

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

	September 30, 2008		June 30, 2008
First lien revolver	$	186,185	$	192,000
High yield facility		750,000		750,000
Put premium financing		10,194		9,697
Total debt		946,379		951,697
Less current maturities		8,254		7,093
Total long-term debt	$	938,125	$	944,604

Maturities of long-term debt as of September 30, 2008 are as follows (in thousands):

Twelve Months Ending September 30,
2009	$	8,254
2010		1,940
2011		186,185
2012		750,000
2013		—
Thereafter		—
Total	$	946,379

First Lien Revolver

Our first lien revolver was amended and restated on June 8, 2007. This facility was entered into by our Parent. This facility has a face value of $700 million and matures on June 8, 2011. The credit facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 1.50 percent to 2.25 percent or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.50 percent to 1.25 percent. However, if an additional equity contribution in an amount of at least $50 million is made by our Parent to us, all of the margins above will be subject to a 0.25 percent reduction. This equity investment was made in June 2008.  The credit facility is secured by mortgages on at least 85 percent of the value of our proved reserves. Our initial borrowing base under the facility was $425 million.

On November 19, 2007, the credit facility was further amended.  The amendment, among other things, increased the borrowing base to $450 million, of which approximately $186 million was borrowed as of September 30, 2008 and modified the commodity hedge limitations and minimum liquidity during certain periods.  We incurred $0.7 million to amend the first lien revolver including $0.5 million associated with syndicating the credit facility.

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Our first lien revolving credit facility requires us to maintain certain financial covenants. Specifically, we may not permit our total leverage ratio to be more than 3.5 to 1.0, our interest rate coverage ratio to be less than 3.0 to 1.0, or our current ratio (in each case as defined in our first lien revolving credit facility) to be less than 1.0 to 1.0, in each case, as of the end of each fiscal quarter. In addition, we are subject to various covenants including those limiting dividends and other payments, making certain investments, margin, consolidating, modifying certain agreements, transactions with affiliates, the incurrence of debt, changes in control, asset sales, liens on properties, sale leaseback transactions, entering into certain leases, the allowance of gas imbalances, take or pay or other prepayments, entering into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr., Steven A. Weyel and David West Griffin in their current executive positions, subject to certain exceptions in the event of death or disability to one of these individuals.

The first lien revolving credit facility also contains customary events of default, including, but not limited to non-payment of principal when due, non-payment of interest or fees and other amounts after a grace period, failure of any representation or warranty to be true in all material respects when made or deemed made, defaults under other debt instruments (including the indenture governing the notes), commencement of a bankruptcy or similar proceeding by or on behalf of us or a guarantor, judgments against us or a guarantor, the institution by us to terminate a pension plan or other ERISA events, any change in control, loss of liens, failure to meet financial ratios, and violations of other covenants subject, in certain cases, to a grace period.  As of September 30, 2008, we are in compliance with all covenants.

High Yield Facility

On June 8, 2007 we completed a $750 million private offering of 10 percent Senior Notes due 2013 (“Old Notes”).  As part of the private offering EGC agreed to use its best efforts to complete an exchange offer, which it completed on October 16, 2007.  In the exchange offer, the Old Notes were exchanged for $750 million of 10 percent Senior Notes due 2013 that have been registered under the Securities Act of 1933 (“New Notes”), with terms substantially the same as the Old Notes.  All of the issued and outstanding Old Notes were exchanged for New Notes.  We did not receive any cash proceeds from the exchange offer.

The notes are guaranteed by our Parent and each of our existing and future material domestic subsidiaries. We have the right to redeem the new notes under various circumstances and are required to make an offer to repurchase the new notes upon a change of control and from the net proceeds of asset sales under specified circumstances.

As of September 30, 2008, our Parent has purchased a total of $67.5 million total face amount of the New Notes at an average cost of 87.10, or $58.8 million, plus accrued interest of an incremental $1.0 million for a total cost of $59.8 million.  (See Note 14).

Put Premium Financing

We finance puts that we purchase with our hedge providers. Substantially all of our hedges are done with members of our bank groups. Put financing is accounted for as debt and this indebtedness is pari pasu with borrowings under the first lien revolver. The hedge financing is structured to mature when the put settles so that we realize the value net of hedge financing. As of September 30, 2008 and June 30, 2008, our outstanding hedge financing totaled $10.2 million and $9.7 million, respectively.

Interest Expense

Interest expense for the three months ended September 30, 2008 was $23.3 million, which includes $1.0 million of amortization of debt issuance costs, interest expense of $21.9 million associated with the high yield facility and the first lien revolver and $0.4 million associated with the put premium financing and other.

Interest expense for the three months ended September 30, 2007 was $25.8 million, which includes $1.1 million amortization of debt issuance costs, interest expense of $24.2 million associated with the high yield facility and the first lien revolver and $0.5 million associated with the put premium financing and other.

Note 6 – Note Payable

On July 22, 2008, we entered into a $17.2 million note payable with AFCO Credit Corporation to finance a portion of our insurance premiums. The note is payable in 11 monthly installments of $1,589,988 including interest at an annual rate of 3.249 percent, beginning August 1, 2008.

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Note 7 – Asset Retirement Obligations

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

Total balance at June 30, 2008	$	97,814
Liabilities acquired		-
Liabilities incurred		2,495
Liabilities settled		(6,479	)
Revisions in estimated cash flows		-
Accretion expense		2,461
Total balance at September 30, 2008		96,291
Less current portion		16,809
Long-term balance at September 30, 2008	$	79,482

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. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a component of operating income, whereas gains and losses from the settlement of hedging contracts are recorded in crude oil and natural gas revenue.

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

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 limits the downside risk of adverse price movements, it also limits future gains from favorable movements.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the three months ended September 30, 2008 resulted in a decrease in crude oil and natural gas sales in the amount of $43.9 million. For the three months ended September 30, 2008, we recognized a gain of approximately $0.5 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $0.6 million and an unrealized gain of approximately $0.7 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the three months ended September 30, 2007 resulted in an increase in crude oil and natural gas sales in the amount of $9.5 million. For the three months ended September 30, 2007, we recognized a gain of approximately $0.3 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized loss of approximately $1.7 million and an unrealized loss of approximately $0.3 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

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As of September 30, 2008, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) in thousands):

	Crude Oil										Natural Gas
	Volume (MBbls)		Contract Price (1)		Total						Volume (MMMBtus)		Contract Price (1)		Total						Total
					Asset (Liability)			Fair Value Gain (Loss)							Asset (Liability)			Fair Value Gain (Loss)			Fair Value			Fair Value Gain (Loss) (2)
Period
Puts
10/08 - 9/09		26	$	60.00	$	8		$	(58	)		110	$	8.00	$	71		$	(23	)	$	79		$	(81	)
Put Spreads
10/08 - 9/09		1,095		85.00/110.00		13,856			5,758			4,210		6.36/8.36		3,558			1			17,414			5,759
10/09 - 9/10		276		85.00/110.00		3,378			1,377			920		6.50/8.50		715			(8	)		4,093			1,369
						17,234			7,135							4,273			(7	)		21,507			7,128
Swaps
10/08 - 9/09		1,377		73.18		(33,565	)		(21,643	)		7,260		8.55		3,762			3,125			(29,803	)		(18,518	)
10/09 - 9/10		903		70.93		(24,464	)		(15,890	)		6,160		8.23		(1,855	)		(1,207	)		(26,319	)		(17,097	)
10/10 - 9/11		171		70.96		(4,623	)		(3,002	)		1,280		8.12		(622	)		(404	)		(5,245	)		(3,406	)
						(62,652	)		(40,535	)						1,285			1,514			(61,367	)		(39,021	)
Collars
10/08 - 9/09		1,081		81.21/107.68		(6,306	)		(4,066	)		1,412		7.87/10.07		642			169			(5,664	)		(3,897	)
10/09 - 9/10		840		79.84/106.85		(7,506	)		(4,879	)		137		8.00/8.85		(24	)		-			(7,530	)		(4,879	)
10/10 - 9/11		154		77.78/105.31		(1,643	)		(1,068	)												(1,643	)		(1,068	)
						(15,455	)		(10,013	)						618			169			(14,837	)		(9,844	)
Three-Way Collars
10/08 - 9/09		603	53.81/67.37/79.43			(13,544	)		(8,706	)		10,110	5.95/8.11/10.07			4,538			2,943			(9,006	)		(5,763	)
10/09 - 9/10		267	52.30/67.23/81.91			(6,252	)		(4,064	)		9,430	6.00/8.23/10.12			901			583			(5,351	)		(3,481	)
10/10 - 9/11		45	50.95/65.95/82.02			(1,061	)		(690	)		2,260	6.00/8.24/10.13			(18	)		(12	)		(1,079	)		(702	)
						(20,857	)		(13,460	)						5,421			3,514			(15,436	)		(9,946	)
Total Gain (Loss) on Derivatives					$	(81,722	)	$	(56,931	)					$	11,668		$	5,167		$	(70,054	)	$	(51,764	)

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

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

We have reviewed the financial strength of our hedge counterparties and believe the credit risk to be minimal.  At September 30, 2008, we had no deposits for collateral with our counterparties.

On June 26, 2006, we entered into an interest rate costless collar to mitigate the risk of loss due to changes in interest rates.  The dollar amount hedged was $75 million with the interest rate collar being 5.45 percent to 5.75 percent.  At September 30, 2008, we had deferred $1.9 million, net of tax benefit, in losses in OCI related to this instrument.

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The following table reconciles the changes in accumulated other comprehensive income (loss) (in thousands):

Accumulated other comprehensive loss – July 1, 2008	$	(285,010	)
Hedging activities:
Change in fair value of crude oil and natural gas hedging positions		231,176
Change in fair value of interest rate hedging position		203
Accumulated other comprehensive loss – September 30, 2008	$	(53,631	)

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 with respect to which Energy XXI USA, Inc., (the “U.S. Parent”) is the parent entity.  Energy XXI (Bermuda) Limited (the indirect “Foreign Parent”) indirectly owns 100% of U.S. Parent.  FASB Statement 109 provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated group should be based upon a reasonable allocation of the income tax amounts of the consolidated group. Accordingly, the income tax amounts presented herein have been computed by applying the provisions of FASB Statement 109 to Energy XXI and its subsidiaries as if it were a separate 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.

We adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of SFAS No. 109, (“FIN 48”), effective July 1, 2007.  FIN 48 prescribes a minimum recognition threshold and measurement methodology that a tax position taken or expected to be taken in a tax return is required to meet before being recognized in the financial statements. It also provides guidance for derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.  We recognize interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of income. There are no unrecognized tax benefits as of the date of adoption.  There are no unrecognized tax benefits that if recognized would affect the tax rate. There are no interest and penalties recognized as of the date of adoption or for the first quarter.

Our effective tax rate for the three months ended September 30, 2008 and 2007 was approximately 38.3% and 34.3%, respectively.

Note 10 — 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 affect on our financial position or results of operations.

Letters of Credit and Performance Bonds. We had $0.8 million in letters of credit and $11.8 million of performance bonds outstanding as of September 30, 2008.

Drilling Rig Commitments. We have entered into three drilling rig commitments, one commencing on July 14, 2008 at $75,000 per day through April 14, 2009 for a total commitment of $20.6 million and two others at $20,500 per day and $29,800 per day, respectively, until well completions. The last two commitments extend past September 30, 2008, however, the commitment amounts cannot be calculated since the well completion dates are not known.

Note 11 — Fair Value of Financial Instruments

            On July 1, 2008, we adopted the provisions of SFAS No. 157, Fair Value Measurements.  SFAS No. 157 expands the disclosure requirements for financial instruments and other derivatives recorded at fair value, and also requires that a company’s own credit risk be considered in determining the fair value of those instruments. The adoption of SFAS No. 157 resulted in a $10 million pre-tax increase in other comprehensive income and a $10 million reduction of our liabilities to reflect the consideration of our credit risk on our liabilities that are recorded at fair value.

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We use various methods to determine the fair values of our financial instruments and other derivatives which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For our natural gas and oil derivatives, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For our interest rate derivatives, the fair value may be calculated based on these inputs as well as third-party estimates of these instruments. We separate our financial instruments and other derivatives into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our 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 between levels. Each of these levels and our corresponding instruments classified by level are further described below:

• Level 1 instruments’ fair values are based on quoted prices in actively traded markets.  Included in this level is our High Yield Facility debt.

• 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.

• Level 3 instruments’ fair values are based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our valuation models are industry-standard and consider various inputs including third party broker-quoted forward amounts and time value of money.

            Listed below are our financial instruments classified in each level and a description of the significant inputs utilized to determine their fair value at September 30, 2008 (in thousands):

	Level 1		Level 2		Level 3		Total
Assets:
Natural Gas and Oil Derivatives			$	22,601			$	22,601
Liabilities:
High Yield Facility	$	750,000					$	750,000
Natural Gas and Oil Derivatives			$	92,654				92,654
Interest Rate Collar					$	2,875		2,875
Total Liabilities	$	750,000	$	92,654	$	2,875	$	845,529

We believe that the fair value of our high yield facility, classified as Level 1, as of September 30, 2008 was $585.5 million.

The following table sets forth a reconciliation of changes in the fair value of derivatives classified as Level 3 (in thousands):

	Interest Rate Collar
Balance at July 1, 2008	$	(3,187	)
Total loss included in other comprehensive income		(198	)
Settlements		510
Balance at September 30, 2008	$	(2,875	)

As of July 1, 2008, we elected not to adopt SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, for our financial assets and liabilities. SFAS No. 159 provided us the option to record most financial assets and liabilities at fair value on an instrument-by-instrument basis with changes in their fair value reported through the income statement.

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Note 12 — Prepayments and Accrued Liabilities

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

	September 30, 2008		June 30, 2008
Prepaid expenses and other current assets
Advances to joint interest partners	$	22,754	$	12,420
Insurance		14,984		-
Other		2,302		-
Total prepaid expenses and other current assets	$	40,040	$	12,420
Accrued liabilities
Asset retirement obligations-current	$	16,809	$	16,717
Interest		22,081		5,269
Accrued hedge payable		7,565		20,153
Advances from joint interest partners		1,308		7,487
Undistributed oil and gas proceeds		42,748		31,017
Other		3,428		2,340
Total accrued liabilities	$	93,939	$	82,983

Note 13 – Supplemental Cash Flow Information

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

	Three Months Ended September 30,
	2008		2007
Cash paid for interest	$	3,019	$	4,304

Note 14 — Subsequent Events

Repurchase of Debt

Subsequent to September 30, 2008 through October 31, 2008 our Parent has purchased a total of $32.5 million total face amount of the New Notes issued by us at an average cost of 58.00, or $18.9 million, plus accrued interest of an incremental $1.2 million for a total cost of $20.1 million.  (See Note 5).

Hurricanes Gustav and Ike

             We shut in a majority of our production ahead of Hurricanes Gustav and Ike, and have since been working to restore volumes. Although damage to our operated facilities was minimal, the loss of facilities serving two non-operated fields resulted in a long-term reduction of a portion of our pre-storm net production. In addition, restoration of a part of our production is dependent upon repairs to third party operated pipelines and production facilities.  Our insurance deductible is $7.5 million per named storm. Additional sub-sea assessments, systems tests and related evaluations are needed before the full extent of damage will be known. We do not purchase business interruption insurance.

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