Exhibit 99.1
 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2008

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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)

	March 31,		June 30,
	2008		2007
	(Unaudited)
Assets
Current Assets
Cash and cash equivalents	$	784	$	15,265
Accounts receivable
Oil and natural gas sales		95,613		55,763
Joint interest billings		25,488		14,377
Insurance and other		1,372		935
Prepaid expenses and other current assets		17,086		17,678
Deferred income taxes		33,697		—
Royalty deposits		4,548		2,175
Derivative financial instruments		—		17,131
Total Current Assets		178,588		123,324
Property and Equipment
Oil and Gas Properties – full cost method of accounting, net of accumulated       depreciation, depletion, and amortization		1,529,845		1,491,685
Other Assets
Advances to affiliates		3,325		—
Derivative financial instruments		—		616
Deferred income taxes		142		355
Debt issuance costs, net of accumulated amortization		17,973		20,986
Total Other Assets		21,440		21,957
Total Assets	$	1,729,873	$	1,636,966

Liabilities and Stockholder’s Equity
Current Liabilities
Accounts payable	$	68,565		$	79,559
Advances from joint interest partners		5,053			2,026
Accrued liabilities		49,246			24,939
Derivative financial instruments		95,268			1,480
Note payable		3,323			—
Current maturities of long-term debt		4,025			5,369
Total Current Liabilities		225,480			113,373
Long-term debt, less current maturities		1,066,000			1,045,090
Deferred income taxes		—			14,869
Asset retirement obligations		64,304			63,364
Derivative financial instruments		68,435			4,573
Total Liabilities		1,424,219			1,241,269
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 December 31, 2007 and June 30, 2007		1			1
Additional paid-in capital		362,562			362,562
Retained earnings		50,942			30,370
Accumulated other comprehensive income (loss), net of tax		(107,851	)		2,764
Total Stockholder’s Equity		305,654			395,697
Total Liabilities and Stockholder’s Equity	$	1,729,873		$	1,636,966

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						Nine Months Ended
	March 31,						March 31,
	2008			2007			2008			2007
Revenues
Oil sales	$	103,627		$	42,777		$	283,004		$	121,882
Natural gas sales		63,510			34,831			173,342			100,686
Total Revenues		167,137			77,608			456,346			222,568
Costs and Expenses
Lease operating expense		38,342			16,351			102,079			43,819
Production taxes		1,755			1,691			4,987			2,909
Depreciation, depletion and amortization		74,651			28,361			217,092			87,369
Accretion of asset retirement obligation		1,911			877			5,651			2,619
General and administrative expense		4,198			5,704			13,988			16,478
Loss (gain) on derivative financial instruments		2,699			(1,552	)		3,810			(3,110	)
Total Costs and Expenses		123,556			51,432			347,607			150,084
Operating Income		43,581			26,176			108,739			72,484
Other Income (Expense)
Interest income		324			265			1,147			1,247
Interest expense		(26,042	)		(12,638	)		(78,095	)		(39,626	)
Total Other Income (Expense)		(25,718	)		(12,373	)		(76,948	)		(38,379	)
Income Before Income Taxes		17,863			13,803			31,791			34,105
Provision for Income Taxes		6,316			3,988			11,219			11,976
Net Income	$	11,547		$	9,815		$	20,572		$	22,129

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Nine Months Ended
	March 31,
	2008			2007
Cash Flows from Operating Activities
Net income	$	20,572		$	22,129
Adjustments to reconcile net income to net cash provided by
operating activities:
Deferred income tax expense		11,219			11,976
Change in derivative financial instruments		811			10,505
Accretion of asset retirement obligations		5,651			2,619
Depreciation, depletion and amortization		217,092			87,369
Write-off and amortization of debt issuance costs		3,602			5,998
Changes in operating assets and liabilities:
Accounts receivables		(46,989	)		28,481
Prepaid expenses and other current assets		(1,781	)		(35,095	)
Accounts payable and other liabilities		20,385			20,691
Net Cash Provided by Operating Activities		230,562			154,673
Cash Flows from Investing Activities
Acquisitions		(38,880	)		(302,481	)
Capital expenditures		(221,817	)		(248,799	)
Other-net		(114	)		1,400
Net Cash Used in Investing Activities		(260,811	)		(549,880	)
Cash Flows from Financing Activities
Proceeds from long-term debt		204,135			364,000
Payments on long-term debt		(180,159	)		(24,625	)
Advances from (to) affiliates		(3,325	)		70,338
Debt issuance costs		(589	)		(4,741	)
Payments on put financing and other		(4,294	)		(7,434	)
Net Cash Provided by Financing Activities		15,768			397,538
Net Increase (Decrease) in Cash and Cash Equivalents		(14,481	)		2,331
Cash and Cash Equivalents, beginning of period		15,265			4,144
Cash and Cash Equivalents, end of period	$	784		$	6,475

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 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 or stockholder’s equity.

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, 2007.

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

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

Accounting for Uncertainty in Income Taxes. In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48 (“FIN 48”) Accounting for Uncertainty in Income Taxes which is an interpretation of Statement of Financial Accounting Standards (“SFAS”) No. 109 Accounting for Income Taxes. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We believe that FIN 48 may have an impact on our financial statements when there is uncertainty regarding a certain tax position taken or to be taken. In such a situation, the provisions of FIN 48 will be utilized to evaluate, measure and record the tax position, as appropriate. We adopted the provisions of FIN 48 effective July 1, 2007 and the adoption did not have a material impact on our consolidated financial statements.

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Accounting for Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157 Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The provisions of SFAS No. 157 will be applied prospectively as of the beginning of the fiscal year in which it is initially applied except for, among other items, a financial instrument that was measured at fair value at initial recognition under Statement 133 using the transaction price in accordance with the guidance in footnote 3 of Issue 02-3 prior to initial application of SFAS No. 157. We are currently evaluating the impact, if any, of SFAS No. 157 on our consolidated financial statements.

Accounting for Registration Payment Arrangements. In December 2006, the FASB issued FASB Staff Position (“FSP”) EITF 00-19-2, Accounting for Registration Payment Arrangements. This FSP specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies. This FSP further clarifies that a financial instrument subject to a registration payment arrangement should be accounted for in accordance with other applicable GAAP without regard to the contingent obligation to transfer consideration pursuant to the registration payment arrangement. This FSP amends various authoritative literature notably SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and SFAS Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.

This FSP is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to December 21, 2006, the guidance in the FSP is effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. This FSP did not impact our consolidated financial statements.

Accounting for the Fair Value Option for Financial Assets and Financial Liabilities. In February 2007, the FASB issued SFAS No. 159 The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits companies to choose to measure certain financial instruments and certain other items at fair value. SFAS No. 159 requires that we report unrealized gains and losses on items for which we elect the fair value option in earnings. We are required to adopt the provisions of SFAS No. 159 beginning with our first fiscal quarter in fiscal 2009, although the FASB permits earlier adoption. We are currently evaluating the impact of SFAS No. 159, if any, on our consolidated financial statements.

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 effective date of this pronouncement.

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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. 133do 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.

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.

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The following summarized unaudited pro forma financial information for the nine months ended March 31, 2008 assumes that the acquisition of the Partnership oil and gas properties had occurred on July 1, 2007. 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 July 1, 2007 or the results that will be attained in the future (in thousands):

	Nine Months
	Ended
	March 31, 2008
Revenues	$	464,470
Operating Income	$	111,455
Net Income	$	21,325

East Cameron Field

In July 2007, we acquired from ExxonMobil for $3.5 million their 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.

Pogo Properties

On April 24, 2007, we announced that we had conditionally agreed to purchase certain oil and natural gas properties in the Gulf of Mexico (the “Pogo Properties”) from Pogo Producing Company (the “Pogo Acquisition”).  The Pogo Acquisition included working interests in 28 oil and gas fields.

On June 8, 2007, we closed the purchase of these properties for $409.8 million net of approximately $7.8 million in preference rights that were exercised and the assumption of $1.8 million of non current liabilities.

Subsequent to closing it was determined that the preference rights related to the South Pass 49 pipeline would not be exercised so we paid an additional $3 million to Pogo which was accrued at June 30, 2007. We received a preliminary settlement in December 2007 but are still waiting on the final settlement statement for the properties operation for the period from the effective date (April 1, 2007) to the closing date. The allocation between evaluated properties and unevaluated properties is preliminary.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values on June 8, 2007 (in thousands):

Oil and natural gas properties	$	449,223
Asset retirement obligations		(32,244	)
Other non current liabilities		(1,842	)
Cash paid, including acquisition costs of $461	$	415,137

Castex

On June 7, 2006, we entered into a definitive agreement with a number of sellers to acquire certain oil and natural gas properties in Louisiana (the “Castex Acquisition”).  We closed the Castex Acquisition on July 28, 2006.  Our cash cost of the acquisition was approximately $311.2 million.

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The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values on July 28, 2006 (in thousands):

Oil and natural gas properties	$	318,024
Asset retirement obligations		(5,518	)
Cash paid, including acquisition costs of $1,362	$	312,506

The following summarized unaudited pro forma financial information for the nine months ended March 31, 2007 assumes that the Castex Acquisition had occurred on July 1, 2006. 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 July 1, 2006 or the results that will be attained in the future (in thousands):

	Nine Months
	Ended
	March 31, 2007
Revenues	$	228,266
Operating Income	$	71,163
Net Income	$	20,096

The following table reflects the acquisition costs for the nine months ended March 31, 2008 (in thousands):

	Nine Months
	Ended
	March 31, 2008
Partnership Oil and Gas Properties	$	32,544
East Cameron 334/335 Field Acquisition		3,385
POGO Acquisition Closing Adjustment		1,982
Other		969
	$	38,880

Note 4 – Property and Equipment

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

	March 31,		June 30,
	2008		2007
Oil and gas properties
Proved properties	$	1,670,035	$	1,412,890
Less: Accumulated depreciation, depletion and amortization		387,778		165,186
Proved properties – net		1,282,257		1,247,704
Unproved properties		247,588		243,981
Oil and gas properties – net	$	1,529,845	$	1,491,685

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Note 5 – Long-term Debt

Long-term debt follows (in thousands):

	March 31,		June 30,
	2008		2007
First lien revolver	$	316,000	$	292,024
High yield facility		750,000		750,000
Put premium financing		4,025		8,435
Total debt		1,070,025		1,050,459
Less current maturities		4,025		5,369
Total long-term debt	$	1,066,000	$	1,045,090

Aggregate future maturities of long-term debt for the twelve months ending March 31 are as follows: 2009-$4.0 million; 2010-$0.0 million; 2011-$0.0 million; 2012-$316.0 million; 2013-$0.0; thereafter-$750.0 million.

First Lien Revolver

Our first lien revolver was amended and restated on June 8, 2007.  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 us to EGC, all of the margins above will be subject to a 0.25 percent reduction. 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 amended.  The amendment, among other things, increased the borrowing base to $450 million, of which approximately $316.0 million was borrowed as of March 31, 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.

Our first lien revolving credit facility requires us to maintain certain financial covenants. Specifically, our total leverage ratio may not be more than 3.5 to 1.0, our interest rate coverage ratio cannot be less than 3.0 to 1.0, or our current ratio (in each case as defined in our first lien revolving credit facility) cannot 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.

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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 we agreed to use our best efforts to complete an exchange offer, which we 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 us and each of our existing and future material domestic subsidiaries. We have the right to redeem the new notes under various circumstances and will be 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.

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 revolving credit facility. The hedge financing is structured to mature when the put settles so that we realize the value net of hedge financing. As of March 31, 2008 and June 30, 2007, our outstanding hedge financing totaled $4.0 million and $8.4 million, respectively.

Interest Expense

Interest expense for the three months ended March 31, 2008 was $26.0 million, which includes $1.1 million amortization of debt issuance costs, interest expense of $24.7 million associated with the high yield facility and the first lien revolver and $0.2 million associated with the put premium financing.  Interest expense for the three months ended March 31, 2007 was $12.6 million, which includes $0.3 million amortization of debt issuance costs, $11.7 million related to the first and second lien facilities and $0.6 million associated with the put premium financing.

Interest expense for the nine months ended March 31, 2008 was $78.1 million, which includes $3.7 million amortization of debt issuance costs, interest expense of $73.3 million associated with the high yield facility and the first lien revolver debt and $1.1 million associated with the put premium financing and other. Interest expense for the nine months ended March 31, 2007 was $39.6 million, which includes $6.0 million write-off and amortization of debt issuance costs, $32.4 million related to the first and second lien facilities and $1.2 million associated with the put premium financing and other.

Note 6 – Note Payable

In July 2007, we entered into a $17.9 million note payable with AFCO Credit Corporation to finance a portion of our insurance premiums. The note is payable in 11 monthly installments of $1,671,608, including interest at an annual rate of 4.95%, beginning August 1, 2007.  The balance at March 31, 2008 was $3.3 million.

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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, 2007	$	75,829
Liabilities acquired		10,060
Liabilities incurred		10,687
Liabilities settled		(19,933	)
Revisions in estimated cash flows		(6,257	)
Accretion expense		5,651
Total balance at March 31, 2008		76,037
Less current portion		11,733
Long-term balance at March 31, 2008	$	64,304

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 March 31, 2008 resulted in a decrease in crude oil and natural gas sales in the amount of $21.2 million. For the three months ended March 31, 2008, we recognized a loss of approximately $0.1 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized loss of approximately $1.2 million and an unrealized loss of approximately $1.4 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

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Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the three months ended March 31, 2007 resulted in an increase in crude oil and natural gas sales in the amount of $10.4 million. For the three months ended March 31, 2007, we recognized a gain of approximately $0.4 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $6.1 million and an unrealized loss of approximately $5.5 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 nine months ended March 31, 2008 resulted in a decrease in crude oil and natural gas sales in the amount of $20.2 million. For the nine months ended March 31, 2008, we recognized a loss of approximately $0.1 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 $2.0 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 nine months ended March 31, 2007 resulted in an increase in crude oil and natural gas sales in the amount of $22.9 million. For the nine months ended March 31, 2007, we recognized a loss of approximately $1.1 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $8.5 million and an unrealized loss of approximately $4.3 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

As of March 31, 2008, we had the following contracts outstanding:

	Crude Oil				Natural Gas
			Total				Total		Total
	Volume	Contract		Fair Value	Volume	Contract		Fair Value		Fair Value
Period	(MBbls)	Price (1)	(Liability)	(Loss)	(MMMBtus)	Price (1)	(Liability)	(Loss)	(Liability)	(Loss) (2)
			(In thousands)				(In thousands)		(In thousands)
Puts (3)
4/08 – 3/09	83	$60.00	$(25)	$(218)	4,190	$8.00	$(96)	$(2,162)	$(121)	$(2,380)
Swaps
4/08 – 3/09	2,157	78.78	(43,036)	(27,870)	11,750	8.77	(17,904)	(12,402)	(60,940)	(40,272)
4/09 – 3/10	1,075	70.93	(25,045)	(16,297)	6,880	8.40	(7,444)	(4,838)	(32,489)	(21,135)
4/10 – 3/11	579	70.93	(12,408)	(8,075)	4,160	8.12	(2,305)	(1,498)	(14,713)	(9,573)
			(80,489)	(52,242)			(27,653)	(18,738)	(108,142)	(70,980)
Collars
4/08 – 3/09	639	70.32/92.91	(8,830)	(5,685)	2,579	7.94/10.41	(2,166)	(388)	(10,996)	(6,073)
4/09 – 3/10	822	76.58/106.54	(3,442)	(2,164)	562	7.86/9.40	(356)	-	(3,798)	(2,164)
4/10 – 3/11	475	76.49/104.68	(2,072)	(1,307)					(2,072)	(1,307)
			(14,344)	(9,156)			(2,522)	(388)	(16,866)	(9,544)
Three-Way Collars
4/08 – 3/09	768	54.06/67.32/78.87	(16,740)	(10,810)	5,050	5.73/7.53/10.08	(5,268)	(3,424)	(22,008)	(14,234)
4/09 – 3/10	403	53.21/67.48/80.72	(7,438)	(4,796)	2,980	6.00/8.12/9.95	(1,653)	(1,075)	(9,091)	(5,871)
4/10 – 3/11	157	51.55/66.55/82.03	(2,703)	(1,739)	1,320	6.00/8.20/9.92	(106)	(69)	(2,809)	(1,808)
			(26,881)	(17,345)			(7,027)	(4,568)	(33,908)	(21,913)
Total			$(121,739)	$(78,961)			$(37,298)	$(25,856)	$(159,037)	$(104,817)

(1)	The contract price is weighted-averaged by contract volume.
(2)	The (loss) on derivative contracts is net of applicable income taxes.
(3)	Included in natural gas puts are 3,840 MMMBtus of $6 to $8 put spreads for the twelve months ended March 31, 2009.

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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% to 5.75%.  At March 31, 2008, we had deferred $3.0 million, net of tax benefit, in losses in accumulated other comprehensive loss related to this instrument.

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

Accumulated other comprehensive income – July 1, 2007	$	2,764
Hedging activities, net of tax:
Change in fair value of crude oil and natural gas hedging positions		(107,923	)
Change in fair value of interest rate hedging position		(2,692	)
Accumulated other comprehensive loss – March 31, 2008	$	(107,851	)

Note 9 – Income Taxes

We adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of SFAS No. 109, (“FIN 48”), effective July 1, 2007.  The adoption of FIN 48 did not have a material effect on our consolidated financial statements.

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 is no interest or penalties recognized as of the date of adoption or for the nine months ended March 31, 2008.

Our Parent filed our initial income tax return for the tax year ended June 30, 2006 and also our June 30, 2007 tax return.  The tax years ended June 30, 2006 and June 30, 2007 are open for examination by the U.S. and State taxing authorities.

Our effective tax rate for the nine months ended March 31, 2008 and 2007 was approximately 35.3% and 35.1%, 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 March 31, 2008.

Drilling Rig Commitments. We have entered into two drilling rig commitments, one commencing on January 28, 2008 at $87,500 to $100,000 per day until well completion with an option for extension, and the other commencing on March 24, 2008 at $20,500 per day until well completion.

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 Note 11 — Prepaid Expenses and Other Current Assets and Accrued Liabilities

Prepaid expenses and other current assets and accrued liabilities consist of the following (in thousands):

	March 31,		June 30,
	2008		2007
Prepaid expenses and other current assets
Advances to joint interest partners	$	10,748	$	15,678
Insurance		4,326		—
Estimated state tax payments		—		2,000
Other		2,012		—
Total prepaid expenses and other current assets	$	17,086	$	17,678
Accrued liabilities
Asset retirement obligations-current	$	11,733	$	12,465
Interest		24,032		5,795
Due to Pogo for non-exercise of preferential rights		—		3,000
Hedge payables		10,982		—
Other		2,499		3,679
Total accrued liabilities	$	49,246	$	24,939

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