10-Q 1 form10_q.htm 9-30-08 FORM 10-Q form10_q.htm
 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2008

OR

 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 000-52281

Energy XXI (Bermuda) Limited
(Exact name of registrant as specified in its charter)

Bermuda
  
98-0499286
(State or other jurisdiction of incorporation or organization)
  
Identification Number)
     
Canon’s Court, 22 Victoria Street, PO Box HM
    
1179, Hamilton HM EX, Bermuda
  
N/A
(Address of principal executive offices)
  
(Zip Code)
     
Registrant's telephone number, including area code
  
441-295-2244

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 
Yes
x
  
No
o
  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer
o
Accelerated filer
x
Non-accelerated filer
o
Smaller reporting company
o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 
Yes
o
  
No
x
  

As of October 29, 2008, there were 145,289,125 shares outstanding of the registrant’s common stock, par value $0.001 per share.



 
 



 



 
PART I - FINANCIAL INFORMATION
 
 
ITEM 1.     Financial Statements
ENERGY XXI (BERMUDA) LIMITED
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share information)

   
September 30,
    
June 30,
  
   
2008
    
2008
  
ASSETS
  
(Unaudited)
        
Current Assets
            
Cash and cash equivalents
   $ 89,303     $ 168,962  
Accounts receivable
                
Oil and natural gas sales
     56,949       116,678  
Joint interest billings
     28,123       21,322  
Insurance and other
     6,124       4,896  
Prepaid expenses and other current assets
     42,695       14,662  
Royalty deposit
     3,249       4,548  
Deferred income taxes
     442       88,198  
Derivative financial instruments
     18,303       2,179  
Total Current Assets
     245,188       421,445  
Property and Equipment, net of accumulated depreciation, depletion, and amortization
                
Oil and natural gas properties - full cost method of accounting
     1,587,708       1,561,276  
Other property and equipment
     9,797       10,020  
Total Property and Equipment – net
     1,597,505       1,571,296  
Derivative financial instruments
     4,298       3,747  
Deferred income taxes
     2,073       36,055  
Debt issuance costs, net of accumulated amortization
     16,377       17,388  
       Total Assets
   $ 1,865,441     $ 2,049,931  
                 
LIABILITIES
                
Current Liabilities
                
Accounts payable
   $ 88,916     $ 106,751  
Note payable
     12,566       —  
Accrued liabilities
     100,141       98,869  
Derivative financial instruments
     47,213       245,626  
Current maturities of long-term debt
     8,443       7,250  
Total Current Liabilities
     257,279       458,496  
Long-term debt, less current maturities
     870,949       944,972  
Asset retirement obligations
     79,482       81,097  
Derivative financial instruments
     48,316       190,781  
Other
     8,390       —  
Total Liabilities
     1,264,416       1,675,346  
Commitments and Contingencies (Note 12)
                
Stockholders’ Equity
                
Preferred stock, $0.01 par value, 2,500,000 shares authorized and no shares issued at September 30, 2008 and June 30, 2008
     —       —  
Common stock, $0.001 par value, 400,000,000 shares authorized and 145,930,799 and 145,299,675 shares issued and 145,289,125 and 144,937,119 shares outstanding at September 30, 2008 and June 30, 2008, respectively
     146       145  
Additional paid-in capital
     601,950       601,509  
Retained earnings
     52,560       57,941  
Accumulated other comprehensive loss, net of income tax benefit
     (53,631 )     (285,010 )
Total Stockholders’ Equity
     601,025       374,585  
                 
       Total Liabilities and Stockholders’ Equity
   $ 1,865,441     $ 2,049,931  

See accompanying Notes to Consolidated Financial Statements



ENERGY XXI (BERMUDA) LIMITED
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, except per share information)
(Unaudited)

   
Three Months Ended
  
   
September 30,
  
   
2008
    
2007
  
             
Revenues
            
Oil sales
   $ 82,062     $ 87,573  
Natural gas sales
     37,682       56,035  
Total Revenues
     119,744       143,608  
                 
Costs and Expenses
                
Lease operating expense
     34,998       30,693  
Production taxes
     2,036       1,960  
Depreciation, depletion and amortization
     62,409       73,253  
Accretion of asset retirement obligation
     2,461       1,760  
General and administrative expense
     6,235       5,771  
Loss (gain) on derivative financial instruments
     (1,864 )     1,042  
Total Costs and Expenses
     106,275       114,479  
                 
Operating Income
     13,469       29,129  
                 
Other Income (Expense)
                
Interest income
     1,334       498  
Interest expense
     (22,305 )     (26,811 )
Total Other Income (Expense)
     (20,971 )     (26,313 )
                 
Income (Loss) Before Income Taxes
     (7,502 )     2,816  
                 
Income Tax Expense (Benefit)
     (2,851 )     929  
                 
Net Income (Loss)
   $ (4,651 )   $ 1,887  
                 
Earnings (Loss) Per Share
                
Basic
   $ (0.03 )   $ 0.02  
Diluted
   $ (0.03 )   $ 0.02  
                 
Weighted Average Number of Common Stock Outstanding
                
Basic
     144,783       84,135  
Diluted
     144,783       94,321  

See accompanying Notes to Consolidated Financial Statements


ENERGY XXI (BERMUDA) LIMITED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)

   
Three Months Ended
  
   
September 30,
  
   
2008
    
2007
  
             
Cash Flows From Operating Activities
            
Net income (loss)
   $ (4,651 )   $ 1,887  
Adjustments to reconcile net income (loss) to net cash provided by
                
  (used in) operating activities:
                
Deferred income tax expense (benefit)
     (2,851 )     929  
Change in derivative financial instruments
     (1,342 )     (22 )
Accretion of asset retirement obligations
     2,461       1,760  
Depreciation, depletion, and amortization
     62,409       73,253  
Write-off and amortization of debt issuance costs
     694       1,120  
Common stock issued to Directors for services and common stock option expense
     263       67  
Changes in operating assets and liabilities
                
Accounts receivable
     54,068       (21,252 )
Prepaid expenses and other current assets
     (26,734 )     (19,745 )
Accounts payable and other liabilities
     (6,782 )     38,675  
Net Cash Provided by Operating Activities
     77,535       76,672  
                 
                 
Cash Flows from Investing Activities
                
Acquisitions
     —       (3,521 )
Capital expenditures
     (92,603 )     (79,489 )
Other
     —       2  
Net Cash Used in Investing Activities
     (92,603 )     (83,008 )
                 
Cash Flows from Financing Activities
                
Proceeds from the issuance of common stock
     —       32  
Proceeds from long-term debt
     144,751       20,000  
Payments on long-term debt
     (150,083 )     (21,490 )
Purchase of bonds
     (58,792 )     —  
Other
     (467 )     10  
Net Cash Used in Financing Activities
     (64,591 )     (1,448 )
                 
Net Decrease in Cash and Cash Equivalents
     (79,659 )     (7,784 )
                 
Cash and Cash Equivalents, beginning of year
     168,962       19,784  
                 
Cash and Cash Equivalents, end of period
   $ 89,303     $ 12,000  

 
See accompanying Notes to Consolidated Financial Statements
 

 


ENERGY XXI (BERMUDA) LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Basis of Presentation

Nature of Operations.  Energy XXI (Bermuda) Limited (“Energy XXI”) was incorporated in Bermuda on July 25, 2005.  Energy XXI (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company with its principal wholly owned subsidiary, Energy XXI Gulf Coast, Inc. (“EGC”), 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, stockholders’ 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 included in our annual report on Form 10-K 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.

Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. In June 2008, the Financial Accounting Standards Board ("FASB") issued FASB Staff Position ("FSP") No. Emerging Issues Task Force ("EITF") 03-6-1 ("FSP 03-6-1"), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share under the two-class method described in SFAS No. 128, Earnings Per Share. FSP 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years and will require all earnings per share data presented for prior-periods to be restated retrospectively. We currently do not anticipate that FSP 03-6-1 will have a material impact on our earnings per share data for fiscal year 2009 or on earnings per share data for any prior periods presented.

The Hierarchy of Generally Accepted Accounting Principles.  In May 2008, the 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.



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, we acquired a 49.5 percent 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 percent to the general partner and 99 percent 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 49.5 percent 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 proportionate share of the Partnership assets and liabilities were distributed to us.  On December 3, 2007, we paid off our proportionate share of the Partnership debt utilizing our First Lien revolver.

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.


Note 4 – Property and Equipment

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

   
September 30, 2008
    
June 30, 2008
  
Oil and gas properties
            
  Proved properties
   $ 1,914,190     $ 1,816,313  
    Less: Accumulated depreciation, depletion and amortization
     532.431       470,718  
  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  
                 
Other property and equipment
     13,355       12,898  
    Less: Accumulated depreciation
     3,558       2,878  
      Other property and equipment—net
     9,797       10,020  
      Total property and equipment
   $ 1,597,505     $ 1,571,296  

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
     682,500       750,000  
Put premium financing
     10,194       9,697  
Capital lease obligation
     513       525  
Total debt
     879,392       952,222  
Less current maturities
     8,443       7,250  
Total long-term debt
   $ 870,949     $ 944,972  


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

Twelve Months Ending September 30,
      
       
2009
   $ 8,443  
2010
     2,209  
2011
     186,236  
2012
     682,504  
2013
     —  
Thereafter
     —  
      Total
   $ 879,392  

First Lien Revolver

Our first lien revolver was amended and restated on June 8, 2007. This facility was entered into by our subsidiary, EGC. 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. 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.


Our first lien revolving credit facility requires us to maintain certain financial covenants. Specifically, EGC may not permit its 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 our subsidiary, EGC, 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 us and each of EGC’s 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, we have 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.  The New Notes were paid from utilizing a portion of the total warrant proceeds from the warrant tender offer.  The purchased New Notes remain outstanding and accrue interest at 10 percent.  When reflected in the consolidated financials, the face amount of New Notes repurchased will reduce the total amount of New Notes outstanding from $750 million to $682.5 million, and the interest expense will be eliminated against the interest income at the consolidated level.  The $8.7 million pre-tax gain on the New Notes repurchased will be deferred and amortized over the remaining life of the New Notes as the New Notes have not been retired. (See Note 17).

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 $22.3 million, which includes $1.0 million of amortization of debt issuance costs, interest expense of $20.9 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 $26.8 million, which includes $1.1 million amortization of debt issuance costs, interest expense of $25.2 million associated with the high yield facility, the first lien revolver and the Partnership debt 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.


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 $1.1 million and an unrealized loss of approximately $0.2 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.



 
- 10 -

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.

 
- 11 -

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 Bermuda company and we are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States (“U.S.”); accordingly, income taxes have been provided based upon the tax laws and rates of the U.S. 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 38.0% and 33.0%, respectively.

 Note 10 — Employee Benefit Plans
 
       The Energy XXI Services, LLC 2006 Long-Term Incentive Plan (“Incentive Plan”). We adopted an incentive and retention program for our employees. Participation shares (or “Phantom Stock units”) are issued from time to time at a value equal to our common share price at the time of issue. The Phantom Stock units generally vest equally over a three-year period. When vesting occurs, we pay the employee an amount equal to the then current common share price times the number of Phantom Stock units that have vested, plus the cumulative value of dividends applicable to the Company’s stock.  The plan has a limit of 5,000,000 Phantom Stock units.

At our discretion, at the time the Phantom Stock units vest, we have the ability to offer the employee an option to either accept common shares in lieu of cash or to accept cash. Upon a change in control of the Company, all outstanding Phantom Stock units become immediately vested and payable.
 
As of September 30, 2008, we have 4,983,080 unvested Phantom Stock units.  A liability has been recognized as of September 30, 2008 in the amount of $1.7 million, in accrued liabilities in the accompanying consolidated balance sheet. The amount of the liability will be remeasured at fair value as of each reporting date.

 
- 12 -

Restricted Shares activity is as follows:

         
Grant-date
  
   
Number
    
Fair value
  
   
Of Shares
    
Per Share
  
Non-vested at June 30, 2008
     331,666     $ 6.44  
Granted on July 23, 2008
     153,250       4.95  
Granted on September 16, 2008
     459,069       4.95  
Vested during the three months ended September 30, 2008
     (97,500 )        
Non-vested at September 30, 2008
     846,485       4.82  

We determine the fair value of the Restricted Shares based on the market price of our Common Stock on the date of grant.  Compensation cost for the Restricted Shares is recognized on a straight line basis over the vesting or service period.  As of September 30, 2008 there was approximately $4.1 million of the unrecognized compensation cost related to non-vested Restricted Shares.  We expect approximately $1.3 million to be recognized over fiscal 2009, $1.7 million to be recognized during the fiscal year ended 2010, $1.0 million to be recognized during the fiscal year ended 2011 and $0.1 million to be recognized during the fiscal year ended 2012.

Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of Common Stock that have either been purchased by us on the open market or that have been newly issued by us.  In particular, individuals who have been granted restricted stock units pursuant to our 2006 Long-Term Incentive Plan that may be settled in cash may, at our option, use their cash settlement to purchase shares of Common Stock or take the cash settlement.

Defined Contribution Plans.  Our employees are covered by a discretionary noncontributory profit sharing plan.  The plan provides for annual employer contributions based upon 10 percent of annual compensation.  We also sponsor a qualified 401 (k) Plan which provides for matching.  The cost to us under these plans for the three months ended September 30, 2008 and 2007 was $0.5 million for profit sharing and $0.6 million for the 401 (k) Plan and $0.4 million for profit sharing and $0.4 million for the 401 (k) Plan, respectively.

Note 11 — Earnings per Share

Basic earnings per share of common stock is computed by dividing net income by the weighted average number of shares of common stock outstanding during the year.  Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of restricted stock and the potential dilution that would occur if warrants to issue common stock were exercised.  The following table sets forth the calculation of basic and diluted earnings per share (“EPS”) (in thousands, except per share data):

   
Three Months Ended
  
   
September 30,
  
   
2008
    
2007
  
             
Net Income (Loss)
   $ (4,651 )   $ 1,887  
                 
Weighted average shares outstanding for basic EPS
     144,783       84,135  
Add dilutive securities: warrants and unit purchase options
     -       10,186  
Weighted average shares outstanding for diluted EPS
     144,783       94,321  
                 
Earnings (Loss) Per Share
                
Basic
   $ (0.03 )   $ 0.02  
Diluted
   $ (0.03 )     0.02  


 
- 13 -


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 affect on our financial position or results of operations.

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on December 31, 2017.  Future minimum lease commitments as of September 30, 2008 under the operating leases are as follows (in thousands):

Twelve Months Ending September 30,
      
       
2009
   $ 1,346  
2010
     1,346  
2011
     1,346  
2012
     1,346  
2013
     1,346  
Thereafter
     5,705  
Total
   $ 12,435  

Rent expense for the three months ended September 30, 2008 and 2007 was approximately $547,000 and $146,000, respectively.

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 13 — 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.

 
- 14 -
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
   $ 682,500                   $ 682,500  
   Natural Gas and Oil Derivatives
           $ 92,654             92,654  
   Interest Rate Collar
                   $ 2,875       2,875  
   Total Liabilities
   $ 682,500     $ 92,654     $ 2,875     $ 778,029  

We believe that the fair value of our high yield facility, classified as Level 1, as of September 30, 2008 was $532.8 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.

 
- 15 -

Note 14 — 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     $ 10,096  
     Insurance
     14,984       173  
     Investment in EXXI common stock
     2,213       2,199  
     Other
     2,744       2,194  
         Total prepaid expenses and other current assets
   $ 42,695     $ 14,662  
                 
Accrued liabilities
                
Asset retirement obligations-current
   $ 16,809     $ 16,717  
Employee benefits and payroll
     4,448       12,755  
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
     5,182       5,471  
   Total accrued liabilities
   $ 100,141     $ 98,869  

Note 15 – 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
   $ 3,270     $ 4,329  


Note 16 — Dividends

On September 9, 2008, our Board of Directors (“Board”) declared a cash dividend of $0.005 per common share, payable on October 20, 2008 to shareholders of record on September 19, 2008.    Dividend levels are determined by the Board based on profitability, capital expenditures, financing and other factors.

Note 17 — Subsequent Events

Repurchase of Debt

Subsequent to September 30, 2008 through October 31, 2008, we have purchased a total of $32.5 million total face amount of the new notes issued by EGC 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).
 

 
- 16 -

 
        Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this report and with our Annual Report on Form 10-K for the year ended June 30, 2008 (“the 2008 Annual Report”), along with Management’s and Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report.  The following discussion includes forward looking statements that reflect our plans, estimates and beliefs.  Our actual results could differ materially from those discussed in these forward-looking statements.  Factors that could cause or contribute to such differences include, but are not limited to those discussed under “Item 1A Risk Factors.”

  General
 
  We are an independent oil and natural gas exploration and production company whose growth strategy emphasizes acquisitions of oil and natural gas properties, enhanced by our value-added organic drilling program. Our properties are primarily located in the U.S. Gulf of Mexico waters and the Gulf Coast onshore. We were originally formed in July 2005 as an exempted company under the laws of Bermuda to serve as a vehicle for the acquisition of oil and natural gas reserves and related assets. In October 2005, we completed a $300 million initial public offering of common stock and warrants on the AIM of the London Stock Exchange. To date, we have completed three major acquisitions of oil and natural gas properties and have listed our common stock on the NASDAQ Capital Market.

     We operate geographically focused producing reserves and target the acquisition of oil and natural gas properties with which we can add value by increasing production and ultimate recovery of reserves, whether through exploitation or exploration, often using reprocessed seismic data to identify previously overlooked opportunities.


 
- 17 -

 
Operational Information

The following table presents our significant operational information for the periods indicated (in thousands except for unit amounts).


   
Quarter Ended
  
   
Sept. 30,
2008
    
June 30,
2008
    
Mar. 31,
2008
    
Dec. 31,
2007
    
Sept. 30,
2007
  
 
Operating revenues
                              
Crude oil sales
   $ 119,214     $ 160,118     $ 126,660     $ 108,487     $ 89,287  
Natural gas sales
     44,442       77,356       61,675       53,759       44,838  
Hedge gain (loss)
     (43,912 )     (58,712 )     (21,198 )     (8,521 )     9,483  
Total revenues
     119,744       178,762       167,137       153,725       143,608  
Percent of operating revenues from crude oil
                                        
   Prior to hedge gain (loss)
     72.8 %     67.4 %     67.3 %     66.9 %     66.6 %
   Including hedge gain (loss)
     68.5 %     62.5 %     62.0 %     60.7 %     61.0 %
Operating expenses
                                        
   Lease operating expense
                                        
Insurance expense
     4,918       3,932       4,642       4,812       4,832  
Workover and maintenance
     3,873       6,741       5,447       4,489       5,720  
Direct lease operating expense
     26,207       29,108       28,253       24,742       20,141  
       Total lease operating expense
     34,998       39,781       38,342       34,043       30,693  
   Production taxes
     2,036       3,699       1,755       1,272       1,960  
   Depreciation, depletion and amortization
     62,409       83,462       75,268       75,406       73,253  
   General and administrative
     6,235       10,123       4,912       5,644       5,771  
   Other – net
     597       5,932       4,611       903       2,802  
   Total operating expenses
     106,275       142,997       124,888       117,268       114,479  
Operating income
   $ 13,469     $ 35,765     $ 42,249     $ 36,457     $ 29,129  
                                         
Sales volumes per day
                                        
Natural gas (MMcf)
     46.8       67.9       73.3       78.1       83.5  
Crude oil (MBbls)
     11.0       15.1       13.9       13.0       12.3  
Total (MBOE)
     18.8       26.4       26.1       26.0       26.2  
Percent of sales volumes from crude oil
     58.5 %     57.2 %     53.3 %     50.0 %     46.9 %
                                         
Average sales price
                                        
Natural gas per Mcf
   $ 10.33     $ 12.52     $ 9.25     $ 7.48     $ 5.83  
Hedge gain (loss) per Mcf
     (1.57 )     (1.66 )     0.28       0.93       1.46  
Total natural gas per Mcf
   $ 8.76     $ 10.86     $ 9.53     $ 8.41     $ 7.29  
                                         
Crude oil per Bbl
   $ 117.75     $ 116.90     $ 100.10     $ 90.71     $ 79.19  
Hedge loss per Bbl
     (36.70 )     (35.38 )     (18.20 )     (12.68 )     (1.52 )
Total crude oil per Bbl
   $ 81.05     $ 81.52     $ 81.90     $ 78.03     $ 77.67  
                                         
Total hedge gain (loss) per BOE
   $ (25.39 )   $ (24.46 )   $ (8.92 )   $ (3.56 )   $ 3.94  
                                         
Operating revenues per BOE
   $ 69.23     $ 74.49     $ 70.33     $ 64.24     $ 59.63  
Operating expenses per BOE
                                        
   Lease operating expense
                                        
Insurance expense
     2.84       1.64       1.95       2.01       2.00  
Workover and maintenance
     2.24       2.81       2.29       1.88       2.38  
Direct lease operating expense
     15.15       12.13       11.89       10.34       8.36  
       Total lease operating expense
     20.23       16.58       16.13       14.23       12.74  
   Production taxes
     1.18       1.54       0.74       0.53       0.81  
Depreciation, depletion and amortization
     36.08       34.78       31.67       31.51       30.42  
General and administrative
     3.60       4.22       2.07       2.36       2.40  
Other – net
     0.35       2.47       1.94       0.38       1.16  
Total operating expenses
     61.44       59.59       52.55       49.01       47.53  
Operating income per BOE
   $ 7.79     $ 14.90     $ 17.78     $ 15.23     $ 12.10  

 
- 18 -




Results of Operations

Three Months Ended September 30, 2008 Compared With the Three Months Ended September 30, 2007.

Our consolidated net loss for the three months ended September 30, 2008 was $4.7 million or $0.03 diluted loss per common share (“per share”) as compared to net income of $1.9 million for the three months ended September 30, 2007 or $0.02 diluted earnings per share. The decrease is primarily due to lower production volumes partially offset by higher commodity prices. Below is a discussion of prices, volumes and revenue variances.

Price and Volume Variances

   
Three Months Ended September 30,
                    
   
2008
    
2007
    
Increase (Decrease)
    
Percent
Increase (Decrease)
    
Revenue
Increase (Decrease)
  
                           
(In Thousands)
  
Price Variance (1)
                              
  Crude oil sales prices (per Bbl)
   $ 81.05     $ 77.67     $ 3.38       4.4 %   $ 3,420  
  Natural gas sales prices (per Mcf)
     8.76       7.29       1.47       20.2 %     6,327  
        Total price variance
                                     9,747  
                                         
Volume Variance
                                        
  Crude oil sales volumes (MBbls)
     1,012       1,127       (115 )     (10.2 )%     (8,931 )
  Natural gas sales volumes (MMcf)
     4,304       7,685       (3,381 )     (44.0 )%     (24,680 )
  BOE sales volumes (MBOE)
     1,730       2,408       (678 )     (28.2 )%        
  Percent of BOE from crude oil
     58.5 %     46.8 %                        
        Total volume variance
                                     (33,611 )
                                         
        Total price and volume variance
                                   $ (23,864 )

(1)  Commodity prices include the impact of hedging activities.

Revenue Variances

   
Three Months Ended September 30,
              
   
2008
    
2007
    
Decrease
    
Percent
Decrease
  
   
(In Thousands)
        
                         
Crude oil
   $ 82,062     $ 87,573     $ (5,511 )     (6.3 )%
Natural gas
     37,682       56,035       (18,353 )     (32.8 )%
       Total revenues
   $ 119,744     $ 143,608     $ (23,864 )     (16.6 )%

Revenues

Our consolidated revenues decreased $23.9 million in the first quarter of fiscal 2009 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower production volumes which were impacted by effects of Hurricanes Gustav and Ike and reduced revenues by $33.6 million.  Such impact was partially offset by higher commodity prices resulting in increased revenues of $9.7 million. Revenue variances related to commodity prices and sales volumes are described below.

 
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Price Variances

Commodity prices are one of our key drivers of earnings generation and net operating cash flow.  Higher commodity prices contributed $9.7 million in revenues in the first quarter of fiscal 2009. Average natural gas prices, including a $1.57 realized loss per Mcf related to hedging activities, increased $1.47 per Mcf during the first quarter of fiscal 2009, resulting in increased revenues of $6.3 million. Average crude oil prices, including a $36.70 realized loss per barrel related to hedging activities, increased $3.38 per barrel in the first quarter of fiscal 2009, resulting in increased revenues of $3.4 million.  Commodity prices are affected by many factors that are outside of our control. Therefore, commodity prices we received during the first quarter of fiscal 2009 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time could result in reduced cash from operating activities, potentially causing us to expend less on our capital program.  Lower spending on our capital program could result in a reduction of the amount of production volumes we are able to produce. We cannot accurately predict future commodity prices, and cannot be certain whether these events will occur.

Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow.  Lower sales volumes in the first quarter of fiscal 2009 resulted in decreased revenues of $33.6 million. Crude oil sales volumes decreased 115 MBbls in the first quarter of fiscal 2009, resulting in decreased revenues of $8.9 million. Natural gas sales volumes decreased 3,381 MMcf in the first quarter of fiscal 2009, resulting in decreased revenues of $24.7 million.  The decrease in crude oil and natural gas sales volumes in the first quarter of fiscal 2009 was primarily due to the impact of Hurricanes Gustav and Ike partially offset by our exploration and development programs.

As mentioned above, depressed commodity prices over an extended period of time or other unforeseen events could occur that would result in our being unable to sustain a capital program that allows us to meet our production growth goals. However, we cannot predict whether such events will occur.

Below is a discussion of Costs and expenses and Other (income) expense.

 Costs and expenses and Other (income) expense

   
Three Months Ended September 30,
    
Increase
  
   
2008
    
2007
    
(Decrease)
  
   
Amount
    
Per BOE
    
Amount
    
Per BOE
    
Amount
  
Costs and expenses
  
(In Thousands, except per unit amounts)
  
  Lease operating expense
                              
      Insurance expense
   $ 4,918     $ 2.84     $ 4,832     $ 2.00     $ 86  
      Workover and maintenance
     3,873       2.24       5,720       2.38       (1,847 )
      Direct lease operating expense
     26,207       15.15       20,141       8.36       6,066  
         Total lease operating expense
     34,998       20.23       30,693       12.74       4,305  
  Production taxes
     2,036       1.18       1,960       0.81       76  
  DD&A
     62,409       36.08       73,253       30.42       (10,844 )
  Accretion of asset retirement obligation
     2,461       1.43       1,760       0.73       701  
  General and administrative expense
     6,235       3.60       5,771       2.40       464  
  Loss (gain) on derivative financial instruments
     (1,864 )     (1.08 )     1,042       0.43       (2,906 )
        Total costs and expenses
   $ 106,275     $ 61.44     $ 114,479     $ 47.53     $ (8,204 )
                                         
Other (income) expense
                                        
  Interest income
   $ (1,334 )   $ (0.77 )   $ (498 )   $ (0.21 )   $ (836 )
  Interest expense
     22,305       12.90       26,811       11.13       (4,506 )
        Total other (income) expense
   $ 20,971     $ 12.13     $ 26,313     $ 10.92     $ (5,342 )


 
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Costs and expenses decreased $8.2 million in the first quarter of fiscal 2009.  This decrease in costs and expenses was primarily due to the items discussed below.

DD&A expense decreased $10.8 million primarily due to decreased production as a result of the impact of Hurricanes Gustav and Ike ($20.6 million) partially offset by a higher DD&A rate ($9.8 million).  Lease operating expense increased $4.3 million in the first quarter of fiscal 2009 compared to the first quarter of fiscal 2008.  This increase is primarily due to higher well operating expenses stemming from the increase in properties resulting from acquisitions as well as an increase in general operating costs, which include direct expenses incurred to operate our wells and equipment on producing leases. We typically incur higher direct operating costs associated with operating wells that produce higher percentages of oil versus natural gas.  As we increased our percentage production of oil during the first quarter of fiscal 2009, partially as a result of the acquisition of the properties from Pogo Producing Company, our lease operating expenses per BOE have increased.  In addition to increased costs per BOE due to a change in mix of production, well operating expenses were higher in general due to increased fuel, chemical and electricity expenses and higher repair and maintenance expenses.

Other (income) expense decreased $5.3 million in the first quarter of fiscal 2009.  This decrease was primarily due to the items discussed below.

Interest income increased $0.8 million due primarily to higher interest bearing investments partially offset by lower interest rates.  Interest expense decreased $4.5 million due to the additional payments of debt.  On a per unit of production basis, interest expense increased 15.9 percent, from $11.13/BOE to $12.90/BOE.


Income Tax Expense

Income tax expense decreased $3.8 million in the first quarter of fiscal 2009 compared to the first quarter of fiscal 2008, primarily due to a decrease in income before income taxes of $10.3 million and to an increase in the effective income tax rate from 33.0 percent to 38.0 percent.

Liquidity
 
Overview
 
Our principal requirements for capital are to fund our exploration, development and acquisition activities and to satisfy our contractual obligations, primarily for the repayment of debt and any amounts owed during the period related to our hedging positions
 
We have incurred substantial indebtedness in connection with our acquisitions, including the $750 million senior notes offering we completed on June 8, 2007 to fund the Pogo Acquisition and to repay our second lien revolving credit facility. At September 30, 2008, we had $879.4 million of indebtedness outstanding, consisting of $682.5 million in our high yield facility, $186.2 million under our first lien revolving credit facility, $10.2 million in put financings and $0.5 million in capital lease obligations. This debt position is partially offset on a net basis by $89.3 million of cash and cash equivalents on hand at September 30, 2008.  We expect to fund our operations and capital expenditures and satisfy our debt service obligations through operating cash flow, borrowings under our first lien revolving credit facility and additional funds raised from our recent early warrant exercise.  Expansion capital expenditures are directly related to new development opportunities and growth of our reserve base and production at attractive returns.

 
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Capital Resources
 
        Our updated fiscal 2009 capital budget, excluding acquisitions, for the exploration and development programs is approximately $250 million, including $86.6 million spent in the first quarter of fiscal 2009, compared with fiscal 2008 capital expenditures of $330 million and our initial fiscal 2009 capital budget of $380 million.  Our fiscal 2009 budget was adjusted downward to preserve liquidity and to increase our financial flexibility to pursue acquisition opportunities given the volatility in credit and commodity markets. We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, and future acquisitions from cash on hand, cash flows from our operations and borrowings under our credit facility. Notwithstanding the continued weakness in credit markets, we believe our available liquidity will be sufficient to meet our funding requirements through fiscal 2009 and for the foreseeable future.  If an acquisition opportunity arises, we may also seek to access public markets to issue additional debt and/or equity securities. Cash flows from operations were used primarily to fund exploration and development expenditures during the three months ended September 30, 2008.  In June 2007, we also completed our $750 million high yield facility, which enabled us to pay off our second lien facility and help fund the Pogo Acquisition.  At September 30, 2008 we had a working capital deficit of $12.1 million.
 
Net cash provided by operating activities in the first quarter of fiscal 2009 was $77.5 million as compared to $76.7 million in the first quarter of fiscal 2008.  The increase is primarily due to higher commodity prices (including hedging activities), higher changes in operating assets and liabilities and lower costs and expenses, excluding non-cash expenses partially offset by lower production volumes.  Key drivers of net operating cash flows are commodity prices, production volumes and costs and expenses. Average natural gas prices increased 20.2 percent in the first quarter of fiscal 2009 from the same period last year. Crude oil prices increased 4.4 percent in the first quarter of fiscal 2009 from the same period last year.  In the first quarter of fiscal 2009, natural gas and crude oil volumes decreased 44.0 percent and 10.2 percent from the same period last year, respectively.

Contractual Obligations

Information about contractual obligations at September 30, 2008 did not change materially from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended June 30, 2008.

Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 of Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended June 30, 2008.  Also refer to the Notes to Consolidated Financial Statements included in Part 1, Item 1 of this report.

Recent Accounting Pronouncements

For a description of recent accounting pronouncements, see Item 1. Financial Statements – Note 2 – Recent Accounting Pronouncements.

 
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Market-Sensitive Instruments and Risk Management

Market risk is the potential loss arising from adverse changes in market rates and prices, such as commodity prices and interest rates. Our primary market risk exposure is commodity price risk. The exposure is discussed in detail below:

Commodity Price Risk

We utilize commodity-based derivative instruments 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, three-way collars and zero-cost collars. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded in income, whereas gains and losses from the settlement of hedging contracts are recorded in crude oil and natural gas revenues.
 
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 any 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.  Based on the September 30, 2008 published forward commodity price curves for the underlying commodities, a price increase of 10 percent per Bbl for crude oil would increase the fair value of our net commodity derivative liability by approximately $51 million. A price increase of 10 percent per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $20 million.

Derivative instruments are reported on the balance sheet at fair value as short-term or long-term derivative financial instruments assets or liabilities. 

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.
 
Disclosure of Limitations
 
Our ultimate realized gain or loss with respect to commodity price fluctuations will depend on the future exposures that arise during the period as well as our hedging strategies and commodity prices at the time.

          Interest Rate Risk
 
On June 26, 2006, we entered into 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, the fair value of this instrument which was designated as a financial hedge, prior to the impact of federal income tax, was a loss of $2.9 million.
 
A one percent increase in interest rates would increase our interest expense approximately $0.8 million for the remainder of fiscal 2009.
 
    We will generally invest cash equivalents in high-quality credit instruments consisting primarily of money market funds with maturities of 90 days or less. We do not expect any material loss from cash equivalents and therefore we believe its interest rate exposure on invested funds is not material.

 
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Under the supervision and with the participation of certain members of our management, including the Chief Executive Officer and Chief Financial Officer, we completed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and Chief Financial Officer believe that the disclosure controls and procedures were effective as of the end of the period covered by this report with respect to timely communicating to them and other members of management responsible for preparing periodic reports all material information required to be disclosed in this report as it relates to our Company and its consolidated subsidiaries.

Our management does not expect that its disclosure controls and procedures or its internal control over financial reporting will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some person or by collusion of two or more people. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Accordingly, our disclosure controls and procedures are designed to provide reasonable, not absolute, assurance that the objectives of our disclosure control system are met and, as set forth above, our management has concluded, based on their evaluation as of the end of the period, that our disclosure controls and procedures were sufficiently effective to provide reasonable assurance that the objectives of our disclosure control system were met.

There was no change in our internal control over financial reporting during our last quarterly period ended September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 
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PART II - OTHER INFORMATION

ITEM 1.                           Legal Proceedings

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.

ITEM 1A.                       Risk Factors

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended June 30, 2008. 

ITEM 2.                           Unregistered Sales of Equity Securities and Use of Proceeds

Purchases and Distributions of Equity Securities are as follow:

   
Total Number
    
Average Price
        
Period
  
Of Shares
    
Per Shares
    
Total
  
               
(In thousands)
  
                   
Purchases
                  
   Month Ended September 30, 2008
     579,388     $ 3.12     $ 1,809  
                         
Distributions
                        
   Month Ended July 31, 2008
     22,476     $ 5.67     $ 127  
   Month Ended August 31, 2008
     244,267       4.45       1,086  
   Month Ended September 30, 2008
     33,527       3.36       113  
   Total Distributions
     300,270       4.42     $ 1,326  

       We adopted an incentive and retention program for our employees. Participation shares (or “Phantom Stock units”) are issued from time to time at a value equal to our common share price at the time of issue. The Phantom Stock units generally vest equally over a three-year period. When vesting occurs, we pay the employee an amount equal to the then current common share price times the number of Phantom Stock units that have vested, plus the cumulative value of dividends applicable to the Company’s stock.  The plan has a limit of 5,000,000 Phantom Stock units.  <?xml:namespace prefix = o ns = "urn:schemas-microsoft-com:office:office" />
 
               
 
                At our discretion, at the time the Phantom Stock units vest, we have the ability to offer the employee an option to accept common shares in lieu of cash.

 
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ITEM 6.                      Exhibits

The following exhibits are filed as part of this report.

Exhibit
    
Number
  
Description
     
  31.1  
Rule 13a-14(a)/15d-14(a) Certification of the Chairman and Chief Executive Officer Under Section 302
of the Sarbanes-Oxley Act of 2002
     
       
  31.2  
Rule 13a-14(a)/15d-14(a) Certification of the Chief Financial Officer Under Section 302 of
the Sarbanes-Oxley Act of 2002
     
       
  32.1  
Section 1350 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
       
  32.2  
Section 1350 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002





 
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


 
ENERGY XXI (BERMUDA) LIMITED
     
     
 
By
/S/ DAVID WEST GRIFFIN
   
David West Griffin
   
Chief Financial Officer
     
     
 
By
/S/ HUGH A. MENOWN
   
Hugh A. Menown
   
Vice President, Chief Accounting Officer and Chief Information Officer
   


Date:   November 4, 2008


 
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