10-Q 1 v340511_10q.htm 10-Q

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



 

FORM 10-Q



 

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

For the quarterly period ended March 31, 2013

OR

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

For the transition period from             to            

Commission File Number: 001-33628



 

ENERGY XXI (BERMUDA) LIMITED

(Exact name of registrant as specified in its charter)



 

 
Bermuda   98-0499286
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
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)

(441) 295-2244

(Registrant's telephone number, including area code)



 

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 þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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

 
Large accelerated filer þ   Accelerated filer o
Non-accelerated filer o
(Do not check if a smaller reporting company)
  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 þ

As of April 26, 2013, there were 79,374,772 shares outstanding of the registrant’s common stock, par value $0.005 per share.

 

 


 
 

TABLE OF CONTENTS

ENERGY XXI (BERMUDA) LIMITED
TABLE OF CONTENTS

 
  Page
GLOSSARY OF TERMS     1  
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS     4  
PART I — FINANCIAL INFORMATION
        

ITEM 1.

Financial Statements

    5  

ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results
of Operations

    30  

ITEM 3.

Quantitative and Qualitative Disclosures About Market Risk

    42  

ITEM 4.

Controls and Procedures

    43  
PART II — OTHER INFORMATION
        

ITEM 1.

Legal Proceedings

    45  

ITEM 1A.

Risk Factors

    45  

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

    45  

ITEM 3.

Defaults upon Senior Securities

    45  

ITEM 4.

Mine Safety Disclosures

    45  

ITEM 5.

Other Information

    45  

ITEM 6.

Exhibits

    45  
SIGNATURES     46  
EXHIBIT INDEX     47  

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GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this Quarterly Report on Form 10-Q:

     
Bbls   Standard barrel containing 42 U.S. gallons   MMBbls   One million Bbls
Mcf   One thousand cubic feet   MMcf   One million cubic feet
Btu   One British thermal unit   MMBtu   One million Btu
BOE   Barrel of oil equivalent. Natural gas is converted into one BOE based on six Mcf of gas to one barrel of oil   MBOE   One thousand BOEs
DD&A   Depreciation, Depletion and Amortization   MMBOE   One million BOEs
MBbls   One thousand Bbls     

Call options are contracts giving the holder (purchaser) the right, but not the obligation, to buy (call) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).

Cash-flow hedges are derivative instruments used to mitigate the risk of variability in cash flows from crude oil and natural gas sales due to changes in market prices. Examples of such derivative instruments include fixed-price swaps, fixed-price swaps combined with basis swaps, purchased put options, costless collars (purchased put options and written call options) and producer three-ways (purchased put spreads and written call options). These derivative instruments either fix the price a party receives for its production or, in the case of option contracts, set a minimum price or a price within a fixed range.

Completion refers to the work performed and the installation of permanent equipment for the production of natural gas and/or crude oil from a recently drilled or recompleted well.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. For a complete definition of proved developed oil and gas reserves, refer to Rule 4-10(a) (3) of Regulation S-X as promulgated by the Securities and Exchange Commission (“SEC”).

Development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploitation is drilling wells in areas proven to be productive.

Exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.

Fair-value hedges are derivative instruments used to hedge or offset the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment. For example, a contract is entered into whereby a commitment is made to deliver to a customer a specified quantity of crude oil or natural gas at a fixed price over a specified period of time. In order to hedge against changes in the fair value of these commitments, a party enters into swap agreements with financial counterparties that allow the party to receive market prices for the committed specified quantities included in the physical contract.

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. For a complete definition of a field, refer to Rule 4-10(a) (8) of Regulation S-X as promulgated by the SEC.

Formation is a stratum of rock that is recognizable from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.

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Gathering and transportation is the cost of moving crude oil from several wells into a single tank battery or major pipeline.

Gross acres or gross wells are the total acres or wells in which a working interest is owned.

Horizon is a zone of a particular formation or that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

Independent oil and gas company is a company that is primarily engaged in the exploration and production sector of the oil and gas business.

Lease operating or well operating expenses are expenses incurred to operate the wells and equipment on a producing lease.

Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the Company’s working interest percentage in the properties.

Oil includes crude oil, condensate and natural gas liquids.

Operating costs include direct and indirect expenses, including general and administrative expenses, incurred to manage, operate and maintain our wells and related equipment and facilities.

Plugging and abandonment refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from a stratum will not escape into another or to the surface. Regulations of many states and the federal government require the plugging of abandoned wells.

Production costs are costs incurred to operate and maintain our wells and related equipment and facilities. For a complete definition of production costs, please refer to Rule 4-10(a) (20) of Regulation S-X as promulgated by the SEC.

Productive well is an exploratory, development or extension well that is not a dry well.

Proved area refers to the part of a property to which proved reserves have been specifically attributed.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. For a complete definition of proved reserves, refer to Rule 4-10(a) (22) of Regulation S-X as promulgated by the SEC.

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For a complete definition of proved undeveloped oil and gas reserves, refer to Rule 4-10(a) (4) of Regulation S-X as promulgated by the SEC.

Put options are contracts giving the holder (purchaser) the right, but not the obligation, to sell (put) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).

Reservoir refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Seismic is an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional pictures.

Stratigraphic test well refers to a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types

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of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not drilled in a proved area, or (ii) development-type, if drilled in a proved area.

Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover is the operations on a producing well to restore or increase production and such costs are expensed. If the operations add new proved reserves, such costs are capitalized.

Zone is a stratigraphic interval containing one or more reservoirs.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to those summarized below:

our business strategy;
our financial position;
the extent to which we are leveraged;
our cash flow and liquidity;
declines in the prices we receive for our oil and gas affecting our operating results and cash flows;
economic slowdowns that can adversely affect consumption of oil and gas by businesses and consumers;
uncertainties in estimating our oil and gas reserves;
replacing our oil and gas reserves;
uncertainties in exploring for and producing oil and gas;
our inability to obtain additional financing necessary to fund our operations, capital expenditures, and to meet our other obligations;
availability of drilling and production equipment and field service providers;
disruption of operations and damages due to hurricanes or tropical storms;
availability, cost and adequacy of insurance coverage;
competition in the oil and gas industry;
our inability to retain and attract key personnel;
the effects of government regulation and permitting and other legal requirements; and
costs associated with perfecting title for mineral rights in some of our properties.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, “Item 1A. Risk Factors” and elsewhere in this Quarterly Report and (2) Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2012 (the “2012 Annual Report”).

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share information)

   
  March 31, 2013   June 30,
2012
     (Unaudited)
ASSETS
                 
Current Assets
                 
Cash and cash equivalents   $ 30,229     $ 117,087  
Accounts receivable
                 
Oil and natural gas sales     138,522       126,107  
Joint interest billings     9,260       3,840  
Insurance and other     4,773       5,420  
Prepaid expenses and other current assets     22,794       63,029  
Derivative financial instruments     23,900       32,497  
Total Current Assets     229,478       347,980  
Property and Equipment
                 
Oil and natural gas properties – full cost method of accounting, including $539.4 million and $418.8 million of unevaluated properties not being amortized at March 31, 2013 and June 30, 2012, respectively     3,148,239       2,698,213  
Other property and equipment     16,114       9,533  
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment     3,164,353       2,707,746  
Other Assets
                 
Derivative financial instruments     17,134       45,496  
Debt issuance costs, net of accumulated amortization     29,599       27,608  
Equity method investments     13,408       2,117  
Total Other Assets     60,141       75,221  
Total Assets   $ 3,453,972     $ 3,130,947  
LIABILITIES
                 
Current Liabilities
                 
Accounts payable   $ 172,017     $ 156,959  
Accrued liabilities     121,564       118,818  
Notes payable     1,080       22,211  
Asset retirement obligations     30,130       34,457  
Derivative financial instruments     112        
Current maturities of long-term debt     23,428       4,284  
Total Current Liabilities     348,331       336,729  
Long-term debt, less current maturities     1,227,144       1,014,060  
Deferred income taxes     139,268       104,280  
Asset retirement obligations     283,317       266,958  
Derivative financial instruments     561        
Other liabilities     9,220       3,080  
Total Liabilities     2,007,841       1,725,107  
Commitments and Contingencies (Note 16)
                 
Stockholders’ Equity
                 
Preferred stock, $0.001 par value, 7,500,000 shares authorized at March 31, 2013 and June 30, 2012, respectively
                 
7.25% Convertible perpetual preferred stock, 8,000 shares issued and outstanding at March 31, 2013 and June 30, 2012, respectively            
5.625% Convertible perpetual preferred stock, 813,188 and 814,117 shares issued and outstanding at March 31, 2013 and June 30, 2012, respectively     1       1  
Common stock, $0.005 par value, 200,000,000 shares authorized and 79,373,500 and 79,147,340 shares issued and 79,372,837 and 78,837,697 shares outstanding at March 31, 2013 and June 30, 2012, respectively     397       396  
Additional paid-in capital     1,510,811       1,501,785  
Accumulated deficit     (79,199 )      (153,945 ) 
Accumulated other comprehensive income, net of income tax expense     14,121       57,603  
Total Stockholders’ Equity     1,446,131       1,405,840  
Total Liabilities and Stockholders’ Equity   $ 3,453,972     $ 3,130,947  

 
 
See accompanying Notes to Consolidated Financial Statements

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

       
  Three Months
Ended March 31,
  Nine Months
Ended March 31,
     2013   2012   2013   2012
Revenues
                                   
Oil sales   $ 274,364     $ 312,714     $ 807,518     $ 868,978  
Natural gas sales     29,410       23,282       87,002       92,479  
Total Revenues     303,774       335,996       894,520       961,457  
Costs and Expenses
                                   
Lease operating     86,305       78,447       254,708       223,614  
Production taxes     1,352       1,499       3,765       4,847  
Gathering and transportation     4,411       2,465       18,500       12,013  
Depreciation, depletion and amortization     88,727       88,448       279,378       260,819  
Accretion of asset retirement obligations     7,649       9,762       23,057       29,253  
General and administrative expense     16,092       25,075       59,299       66,543  
(Gain) loss on derivative financial instruments     (632 )      3,495       5,755       (2,506 ) 
Total Costs and Expenses     203,904       209,191       644,462       594,583  
Operating Income     99,870       126,805       250,058       366,874  
Other Income (Expense)
                                   
Loss from equity method investees     (2,587 )            (4,698 )       
Other income – net     523       97       1,425       121  
Interest expense     (27,682 )      (26,887 )      (81,339 )      (82,438 ) 
Total Other Expense     (29,746 )      (26,790 )      (84,612 )      (82,317 ) 
Income Before Income Taxes     70,124       100,015       165,446       284,557  
Income Tax Expense     29,688       8,763       65,418       29,885  
Net Income     40,436       91,252       100,028       254,672  
Induced Conversion of Preferred Stock           6,058             6,058  
Preferred Stock Dividends     2,873       2,739       8,623       10,151  
Net Income Available for Common Stockholders   $ 37,563     $ 82,455     $ 91,405     $ 238,463  
Earnings Per Share
                                   
Basic   $ 0.47     $ 1.06     $ 1.15     $ 3.10  
Diluted   $ 0.46     $ 1.04     $ 1.14     $ 2.92  
Weighted Average Number of Common Shares Outstanding
                                   
Basic     79,365       77,454       79,280       76,803  
Diluted     87,516       87,353       87,471       87,185  

 
 
See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Thousands)
(Unaudited)

       
  Three Months
Ended March 31,
  Nine Months
Ended March 31,
     2013   2012   2013   2012
Net Income   $ 40,436     $ 91,252     $ 100,028     $ 254,672  
Other Comprehensive Income (Loss)
                                   
Crude Oil and Natural Gas Cash Flow Hedges
                                   
Unrealized change in fair value net of ineffective portion     (2,010 )      (59,089 )      (38,393 )      106,915  
Effective portion reclassified to earnings during the period     (7,165 )      (2,075 )      (28,502 )      (25,627 ) 
Total Other Comprehensive Income (Loss)     (9,175 )      (61,164 )      (66,895 )      81,288  
Income Tax (Expense) Benefit     3,211       21,407       23,413       (28,451 ) 
Net Other Comprehensive Income (Loss)     (5,964 )      (39,757 )      (43,482 )      52,837  
Comprehensive Income   $ 34,472     $ 51,495     $ 56,546     $ 307,509  

 
 
See accompanying Notes to Consolidated Financial Statements

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

       
  Three Months
Ended March 31,
  Nine Months
Ended March 31,
     2013   2012   2013   2012
Cash Flows From Operating Activities
                                   
Net income   $ 40,436     $ 91,252     $ 100,028     $ 254,672  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                                   
Depreciation, depletion and amortization     88,727       88,448       279,378       260,819  
Deferred income tax expense     25,625       8,764       58,439       30,036  
Change in derivative financial instruments
                                   
Proceeds from derivative instruments     574       993       735       66,522  
Other – net     (5,318 )      (10,866 )      (19,336 )      (36,557 ) 
Accretion of asset retirement obligations     7,649       9,762       23,057       29,253  
Loss from equity method investees     2,587             4,698        
Amortization and write-off of debt issuance costs     1,910       1,886       5,708       5,591  
Stock-based compensation     483       478       2,139       10,592  
Changes in operating assets and liabilities                                    
Accounts receivable     (1,858 )      (9,565 )      (9,254 )      (27,146 ) 
Prepaid expenses and other current assets     19,541       9,945       40,263       4,879  
Settlement of asset retirement obligations     (4,761 )      (4,569 )      (29,570 )      (6,563 ) 
Accounts payable and accrued liabilities     34,314       11,670       (4,740 )      (25,916 ) 
Net Cash Provided by Operating Activities     209,909       198,198       451,545       566,182  
Cash Flows from Investing Activities
                                   
Acquisitions     (112,566 )      (35 )      (153,722 )      (6,212 ) 
Capital expenditures     (184,504 )      (155,744 )      (563,554 )      (394,188 ) 
Insurance payments received                       6,472  
Net contributions to equity investees     (503 )            (16,027 )       
Proceeds from the sale of properties           203             2,970  
Other     (409 )      1,252       (54 )      444  
Net Cash Used in Investing Activities     (297,982 )      (154,324 )      (733,357 )      (390,514 ) 
Cash Flows from Financing Activities
                                   
Proceeds from the issuance of common and preferred stock, net of offering costs     499       191       5,259       9,647  
Conversion of preferred stock to common           (6,029 )            (6,029 ) 
Dividends to shareholders – common     (5,556 )            (16,659 )       
Dividends to shareholders – preferred     (2,873 )      (2,877 )      (8,623 )      (10,289 ) 
Proceeds from long-term debt     532,990       185,437       1,142,439       707,761  
Payments on long-term debt     (447,653 )      (214,468 )      (928,914 )      (818,787 ) 
Other                 1,452       (854 ) 
Net Cash Provided by (Used in) Financing Activities     77,407       (37,746 )      194,954       (118,551 ) 
Net Increase (Decrease) in Cash and Cash Equivalents     (10,666 )      6,128       (86,858 )      57,117  
Cash and Cash Equivalents, beginning of period     40,895       79,396       117,087       28,407  
Cash and Cash Equivalents, end of period   $ 30,229     $ 85,524     $ 30,229     $ 85,524  

 
 
See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1 — Basis of Presentation

Nature of Operations.  Energy XXI (Bermuda) Limited was incorporated in Bermuda on July 25, 2005. We are 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.

References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

Principles of Consolidation and Reporting.  The accompanying 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 accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended June 30, 2012 (the “2012 Annual Report”).

Use of Estimates.  The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such difference may be material.

Note 2 — Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-05: Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 provides that an entity that reports items of other comprehensive income has the option to present comprehensive income in either one continuous financial statement or two consecutive financial statements. The update is intended to increase the prominence of other comprehensive income in the financial statements. ASU 2011-05 is effective for annual periods beginning after December 15, 2011, with early adoption permitted. We adopted ASU 2011-05 on June 30, 2012 and the adoption had no effect on our consolidated financial position, results of operations or cash flows other than presentation.

In December 2011, the FASB issued Accounting Standards Update No. 2011-12: Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”). ASU 2011-12 defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. As part of this update, the FASB did not defer the requirement to report

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 2 — Recent Accounting Pronouncements  – (continued)

comprehensive income either in a single continuous statement or in two separate but consecutive financial statements. ASU 2011-12 is effective for annual periods beginning after December 15, 2011.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

In February 2013, the FASB issued Accounting Standards Update No. 2013-02: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 updates ASU 2011-12 and requires companies to report information of significant changes in accumulated balances of each component of other comprehensive income (“AOCI”) included in equity in one place. Total changes in AOCI by component can either be presented on the face of the financial statements or in the notes. ASU 2013-02 is effective for fiscal years and interim periods within those years beginning after December 15, 2012, with early adoption permitted. We do not expect the adoption ASU 2013-02 to have any effect on our consolidated financial position, results of operations or cash flows, other than presentation.

Note 3 — Acquisitions

ExxonMobil oil and gas properties interests acquisition

On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“Exxon”) for a total cash consideration of approximately $33.5 million. The GOM Interests cover 5,000 gross acres on Vermilion Block 164 (“VM 164”). We are the operator of these properties. In addition to acquiring the GOM Interests, we entered into a joint venture agreement with Exxon to explore for oil and gas on nine contiguous blocks adjacent to VM 164 in shallow waters on the Gulf of Mexico shelf. We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012. Our total capital commitment for the joint venture in calendar year 2013 is estimated at $75 million, assuming successful completion of two earning wells.

Revenues and expenses related to the GOM Interests from the closing date of October 17, 2012 are included in our consolidated statements of income. The acquisition of the GOM interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on October 17, 2012 (in thousands):

 
Oil and natural gas properties – evaluated   $ 11,088  
Oil and natural gas properties – unevaluated     27,721  
Asset retirement obligations     (5,353 ) 
Cash paid   $ 33,456  

Dynamic Offshore oil and gas properties interests acquisition

On November 7, 2012, we acquired 100% of the interests (“Dynamic Interests”) held by Dynamic Offshore Resources, LLC (“Dynamic”) on VM 164 for approximately $7.2 million.

Revenues and expenses related to the Dynamic Interests from the closing date of November 7, 2012 are included in our consolidated statements of income. The acquisition of the Dynamic Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 3 — Acquisitions  – (continued)

acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

 
Oil and natural gas properties – evaluated   $ 1,716  
Oil and natural gas properties – unevaluated     6,571  
Asset retirement obligations     (1,090 ) 
Cash paid   $ 7,197  

McMoRan oil and gas properties interests acquisition

On January 17, 2013, we closed on the acquisition of certain onshore Louisiana interests in the Bayou Carlin field (“Bayou Carlin Interests”) from McMoRan Oil and Gas, LLC (“McMoRan”) for a total cash consideration of $80 million. This acquisition is effective January 1, 2013. We are the operator of these properties.

Revenues and expenses related to the Bayou Carlin Interests from the closing date of January 17, 2013 are included in our consolidated statements of income. The acquisition of the Bayou Carlin Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

 
Oil and natural gas properties – evaluated   $ 63,186  
Oil and natural gas properties – unevaluated     17,184  
Net working capital     12  
Asset retirement obligations     (382 ) 
Cash paid   $ 80,000  

Roda oil and gas properties interests acquisition

On March 14, 2013, we acquired 100% of the interests (“Roda Interests”) held by Roda Drilling LP (“Roda”) in the Bayou Carlin field for $34 million. This acquisition is effective January 1, 2013.

Revenues and expenses related to the Roda Interests from the closing date of March 14, 2013 are included in our consolidated statements of income. The acquisition of the Roda Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 14, 2013 (in thousands):

 
Oil and natural gas properties – evaluated   $ 33,615  
Net working capital     500  
Asset retirement obligations     (115 ) 
Cash paid   $ 34,000  

The fair values of evaluated and unevaluated oil and gas properties and asset retirement obligations for the above acquisitions were measured using valuation techniques that convert future cash flows to a single discounted amount. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 3 — Acquisitions  – (continued)

Apache Joint Venture

On February 1, 2013, we entered into an Exploration Agreement (“Agreement”) with Apache Corporation (“Apache”) to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central Gulf of Mexico Shelf. We have a 25% participation interest in the Agreement, which expires on February 1, 2018.

The area of mutual interest (“AMI”) under this agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million. We have presently consented to participate in drilling one well and have an option to participate in two other wells under the current drilling program.

As of March 31, 2013, we paid consideration of approximately $2.5 million, being our participation interest, to Apache for non-producing primary-term leases.

Note 4 — Property and Equipment

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

   
  March 31, 2013   June 30,
2012
Oil and gas properties
                 
Proved properties   $ 4,982,071     $ 4,375,984  
Less: Accumulated depreciation, depletion, amortization and impairment     2,373,186       2,096,531  
Proved properties     2,608,885       2,279,453  
Unproved properties     539,354       418,760  
Oil and gas properties     3,148,239       2,698,213  
Other property and equipment     31,273       22,132  
Less: Accumulated depreciation     15,159       12,599  
Other property and equipment     16,114       9,533  
Total property and equipment – net of accumulated depreciation, depletion, amortization and impairment   $ 3,164,353     $ 2,707,746  

Note 5 — Equity Method Investments

  20% interest in Energy XXI M21K, LLC (“EXXI M21K”)

We own a 20% interest in EXXI M21K. EXXI M21K engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K, LLC (“M21K”).

On June 4, 2012, M21K entered into a Purchase and Sale Agreement (“PSA Agreement”) with EP Energy E&P Company, L.P. (“EP Energy”) to acquire interests in certain oil and gas fields owned by EP Energy. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was $103 million. The effective date of the acquisition is January 1, 2012.

On July 19, 2012, M21K closed on the acquisition and we paid our share of the remaining purchase price of $16 million to EP Energy, prior to final adjustments. EXXI M21K is a guarantor of a $100 million first lien credit facility agreement entered into by M21K (“M21K First Lien Credit Agreement”). Simultaneous with the closing of the acquisition of assets from EP Energy, M21K entered into the First Amendment to the M21K First Lien Credit Agreement, which made technical changes to defined terms and hedging requirements, as well as establishing the borrowing base under the facility at $25 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 5 — Equity Method Investments  – (continued)

On December 12, 2012, in conjunction with the name change from Natural Gas Partners Assets, LLC to M21K, LLC, M21K entered into the Second Amendment to the M21K First Lien Credit Agreement to reflect the name change and make technical changes to borrowing procedures.

On April 9, 2013, M21K entered into the Third Amendment to the M21K First Lien Credit Agreement that made technical modification of a defined term and reduced the borrowing base to $24 million with further reduction to $20 million within ninety days from the amendment date.

We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K. See Note 14 — Related Party Transactions of Notes to Consolidated Financial Statements in this Quarterly Report.

As of March 31, 2013, our investment in EXXI M21K was approximately $12.7 million, and we had incurred $1.7 million and $2.0 million in equity losses for the three months and nine months ended March 31, 2013, respectively.

  49% interest in Ping Energy XXI Limited (“Ping Energy”)

Our wholly-owned subsidiary Energy XXI International Limited (“EXXI International”) owns a 49% interest in Ping Energy, which is active in the pursuit to identify and acquire exploratory, developmental and producing oil and gas properties in South East Asia.

As of March 31, 2013, our investment in Ping Energy was approximately $0.7 million and we had incurred $0.9 million and $2.7 million in equity losses for the three months and nine months ended March 31, 2013, respectively.

Note 6 — Long-Term Debt

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

   
  March 31, 2013   June 30,
2012
Revolving credit facility   $ 212,831     $  
9.25% Senior Notes due 2017     750,000       750,000  
7.75% Senior Notes due 2019     250,000       250,000  
4.14% Promissory Note due 2017     5,289        
Derivative instruments premium financing     31,387       17,387  
Capital lease obligation     1,065       957  
Total debt     1,250,572       1,018,344  
Less current maturities     23,428       4,284  
Total long-term debt   $ 1,227,144     $ 1,014,060  

Maturities of long-term debt as of March 31, 2013 are as follows (in thousands):

 
Twelve Months Ended March 31,                                         
        
2014   $ 23,428  
2015     222,331  
2016     813  
2017     465  
2018     753,535  
Thereafter     250,000  
Total   $ 1,250,572  

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Long-Term Debt  – (continued)

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by our indirect, wholly-owned subsidiary, Energy XXI Gulf Coast, Inc. (“EGC”), in May 2011. This facility, amended most recently on May 1, 2013, has lender commitments of $1,700 million and matures on April 9, 2018. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, EGC is allowed to pay us a limited amount of distributions, subject to certain terms and conditions.

On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement, which provided EGC the ability to make distributions to us for various purposes, subject to varying limitations depending on the purpose of the distribution. The ability of EGC to make dividends was subject to EGC meeting minimum liquidity and maximum revolver utilization thresholds, and were further limited to an aggregate cumulative amount equal to $70 million plus 50% of our cumulative Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter. The ability of EGC to make dividend payments to us was modified in subsequent amendments.

On May 24, 2012, EGC entered into the Second Amendment (the “Second Amendment”) to the First Lien Credit Agreement which provided further increased flexibility to make payments from EGC to us and/or our other subsidiaries. The Second Amendment includes the following: (a) removal of limitations on the ability of EGC to finance hedge option premiums; (b) technical modifications in regard to the ability of EGC to reposition hedges; (c) adjustment of definitions and other provisions to further increase the ability of EGC to make distributions to us and/or our subsidiaries; and (d) technical corrections in connection with the replacement of one of the lenders (including that lender’s role as an issuer of a letter of credit) under the First Lien Credit Agreement.

On October 19, 2012, EGC entered into the Third Amendment (the “Third Amendment”) to the First Lien Credit Agreement. The Third Amendment provides changes, supplements, and other modifications for information specific to the lenders under the First Lien Credit Agreement and increases the borrowing base to $825 million.

On April 9, 2013, EGC entered into the Fourth Amendment (the “Fourth Amendment”) to the First Lien Credit Agreement. The Fourth Amendment includes the following: (a) extension of the maturity date to April 9, 2018 (b) increase of commitments under the First Lien Credit Agreement from $925 million to $1,700 million, (c) increase in the borrowing base to $850 million, (d) reduction of the ranges of applicable margins on all borrowing by 0.25% to 0.50%, (e) approval of an increase in the cash distribution basket under which EGC can make dividend payments on its preferred and common stock, from $17 million to $50 million per calendar year, (f) increase in the general basket of permitted unsecured indebtedness from $250 million to $750 million, subject to a reduction in the borrowing base of 25 percent of any unsecured indebtedness issued in excess of $250 million, and (g) approval of additional ability of an affiliated entity to reinsure the assets and operations of EGC and its subsidiaries.

On May 1, 2013, EGC entered into the Fifth Amendment (the “Fifth Amendment”) to the First Lien Credit Agreement. The Fifth Amendment provides changes and other modifications to the First Lien Credit Agreement to increase the ability of EGC to make dividends and other distributions to us. Under the Amendment, EGC now can make such dividends and other distributions in an amount of up to $350 million per calendar year to the extent that, following each distribution, EGC and its subsidiaries have liquidity, in the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Long-Term Debt  – (continued)

form of cash and available borrowing capacity under the First Lien Credit Agreement, of the greater of $150 million or 15% of the borrowing base under the First Lien Credit Agreement. Further, the amendment limits the total aggregate distributions made by EGC to a maximum of $70 million plus 50% of the cumulative consolidated net income of EGC between October 1, 2010 and the most recently ended fiscal quarter, and requires that the making of any such dividend or other distributions must otherwise comply with all contractual restrictions and obligations applicable to EGC.

The First Lien Credit Agreement (as amended) requires EGC to maintain certain financial covenants. Specifically, EGC may not permit the following under First Lien Credit Agreement: (a) EGC’s total leverage ratio to be more than 3.5 to 1.0, (b) EGC’s interest coverage ratio to be less than 3.0 to 1.0, and (c) EGC’s current ratio (in each case as defined in our First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to declare and pay dividends or other payments, our ability to incur debt, changes in control, our ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

As of March 31, 2013, we were in compliance with all covenants under our First Lien Credit Agreement.

High Yield Facilities

9.25% Senior Notes

On December 17, 2010, EGC issued $750 million aggregate principal amount of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Senior Notes”). On July 8, 2011, we exchanged $749 million aggregate principal amount of the 9.25% Notes for $749 million aggregate principal amount of newly issued notes registered under the Securities Act of 1933, as amended (the “Securities Act”) which bear identical terms and conditions as the 9.25% Senior Notes. The trading restrictions on the remaining $1 million principal amount of the 9.25% Senior Notes were lifted on December 17, 2011.

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

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

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of March 31, 2013 was $848.9 million based on quoted prices. There is no active market for the 9.25% Senior Notes; therefore, the fair value is classified within Level 2.

The 9.25% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

7.75% Senior Notes

On February 25, 2011, EGC issued $250 million aggregate principal amount of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Senior Notes”). On July 7, 2011, we exchanged the full $250 million aggregate principal amount of the 7.75% Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act which bear identical terms and conditions as the 7.75% Senior Notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Long-Term Debt  – (continued)

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised. We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

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

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of March 31, 2013 was $271.3 million based on quoted prices. There is no active market for the 7.75% Senior Notes; therefore, the fair value is classified within Level 2.

The 7.75% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

Promissory Note

In September 2012, we entered into a promissory note of $5.5 million to acquire other property and equipment. Under this note we are required to make a monthly payment of approximately $52,000 and one lump-sum payment of $3.3 million at maturity, in October 2017. This note carries an interest of 4.14% per annum.

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value net of derivative instrument premium financing. As of March 31, 2013 and June 30, 2012, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $31.4 million and $17.4 million, respectively.

Interest Expense

For the three months and nine months ended March 31, 2013 and 2012, interest expense consisted of the following (in thousands):

       
  Three Months
Ended March 31,
  Nine Months
Ended March 31,
     2013   2012   2013   2012
Revolving credit facility   $ 3,330     $ 2,201     $ 8,185     $ 7,291  
9.25% Senior Notes due 2017     17,343       17,344       52,031       52,031  
7.75% Senior Notes due 2019     4,843       4,843       14,531       14,531  
Amortization of debt issue cost – Revolving credit facility     1,261       1,238       3,762       3,645  
Amortization of debt issue cost – 9.25% Senior Notes due 2017     552       552       1,655       1,655  
Amortization of debt issue cost – 7.75% Senior Notes due 2019     97       97       291       291  
Derivative instruments financing and other     256       612       884       2,994  
     $ 27,682     $ 26,887     $ 81,339     $ 82,438  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 7 — Notes Payable

In May 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $26.0 million and bore interest at an annual rate of 1.556%. The note matured and was repaid on December 26, 2012.

In July 2012, we entered into a note to finance a portion of our insurance premiums. The note is for a total face amount of $3.6 million and bears interest at an annual rate of 1.667%. The note amortizes over the remaining term of the insurance, which matures May 1, 2013. The balance outstanding as of March 31, 2013 was $0.7 million.

In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums. The note was for a total face amount of $0.6 million and bears interest at an annual rate of 1.774%. The note amortizes over the remaining term of the insurance, which matures October 23, 2013. The balance outstanding as of March 31, 2013 was $0.3 million.

Note 8 — Asset Retirement Obligations

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

 
Balance at June 30, 2012   $ 301,415  
Liabilities acquired     6,940  
Liabilities incurred     11,605  
Liabilities settled     (29,570 ) 
Accretion expense     23,057  
Total balance at March 31, 2013     313,447  
Less current portion     30,130  
Long-term balance at March 31, 2013   $ 283,317  

Note 9 — Derivative Financial Instruments

We enter into hedging transactions with a diversified group of investment-grade rated counterparties, primarily financial institutions, for our derivative transactions to reduce the concentration of exposure to any individual counterparty and to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. We designate a majority of our derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled.

When we discontinue cash flow hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, changes to fair value accumulated in other comprehensive income are recognized immediately into earnings.

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Derivative Financial Instruments  – (continued)

consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX, ICE) plus the difference between the purchased put and the sold put strike price.

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. Historically the basis differential between HLS and WTI has been relatively small and predictable. Over the past five years, HLS has averaged approximately $1 per barrel premium to WTI. Since the beginning of 2011, the HLS/WTI basis differential and volatility has increased with HLS carrying as much as a $30 per barrel premium to WTI. During the quarter ended September 30, 2011, we began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By including Brent benchmarks in our crude hedging, we can more appropriately manage our exposure and price risk.

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

We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended March 31, 2013, and received $181.1 million. These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts. As of March 31, 2013, we had $13.5 million of monetized amounts remaining in OCI of which $4.5 million will be recognized during each of the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013, respectively.

During the quarter ended March 31, 2013, we repositioned certain hedge positions by selling puts on certain existing calendar year 2013 hedge collar contracts and purchasing new put spread contracts. The $2.2 million received from the sale of puts were recorded as deferred hedge revenue and will be recognized in income over the life of the underlying hedge contracts through December 31, 2013. As of March 31, 2013, we had $2.0 million in deferred hedge revenue of which $0.6 million, $0.7 million, and $0.7 million will be recognized during the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Derivative Financial Instruments  – (continued)

As of March 31, 2013, we had the following net open crude oil derivative positions:

             
        Weighted Average Contract Price
           Swaps   Collars/Put Spread
Period   Type of Contract   Index   Volumes (MBbls)   Fixed Price   Sub Floor   Floor   Ceiling
April 2013 – December 2013
    Three-Way Collars       Oil-Brent-IPE       2,570 (1)             $ 85.72     $ 105.72     $ 126.72  
April 2013 – December 2013
    Put Spreads       Oil-Brent-IPE       1,830                87.00       106.25           
April 2013 – December 2013
    Three-Way Collars       NYMEX-WTI       1,375                70.00       90.00       136.32  
April 2013 – December 2013
    Collars       NYMEX-WTI       963                         73.57       105.63  
April 2013 – December 2013
    Swaps       NYMEX-WTI       138     $ 86.60                             
April 2013 – December 2013
    Swaps       NYMEX-WTI       (138 )      88.20                             
January 2014 – December 2014     Three-Way Collars       Oil-Brent-IPE       2,373                68.08       88.08       130.88  
January 2014 – December 2014     Collars       Oil-Brent-IPE       730                         90.00       108.38  
January 2014 – December 2014     Three-Way Collars       NYMEX-WTI       3,650                70.00       90.00       137.14  
January 2015 – December 2015     Three-Way Collars       Oil-Brent-IPE       1,825                72.00       92.00       111.56  

(1) The Oil-Brent-IPE three-way collars for the period from April 2013 through December 2013 include the repositioned derivative contracts referred to above. The newly purchased put spreads have been designated as hedges whereas the call option remaining from the collar after the put was sold no longer qualifies for hedge accounting. However, the combination of the put spread and call contracts effectively result into a three-way collar.

As of March 31, 2013, we had the following open natural gas derivative positions:

           
        Weighted Average Contract Price
           Collars/Call Spread
Period   Type of Contract   Index   Volumes (MMBtu)   Sub Floor   Floor   Ceiling
April 2013 – December 2013
    Three-Way Collars       NYMEX-HH       8,250     $ 4.07     $ 4.93     $ 5.87  
January 2014 – December 2014
    Call Spread       NYMEX-HH       913       4.20       5.00  

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Derivative Financial Instruments  – (continued)

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

               
               
  Asset Derivative Instruments   Liability Derivative Instruments
     March 31, 2013   June 30, 2012   March 31, 2013   June 30, 2012
     Balance Sheet Location   Fair
Value
  Balance Sheet Location   Fair
Value
  Balance Sheet Location   Fair
Value
  Balance Sheet Location   Fair
Value
Commodity Derivative Instruments designated as hedging instruments:
                                                                       
Derivative financial instruments
    Current     $ 37,233       Current     $ 66,716       Current     $ 13,622       Current     $ 34,462  
       Non-Current       43,294       Non-Current       103,462       Non-Current       26,896       Non-Current       58,229  
Commodity Derivative Instruments not designated as hedging instruments:
                                                                       
Derivative financial instruments
    Current       4,621       Current       326       Current       4,444       Current       83  
       Non-Current       319       Non-Current       451       Non-Current       144       Non-Current       188  
Total         $ 85,467           $ 170,955           $ 45,106           $ 92,962  

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

       
  Three Months Ended March 31,   Nine Months Ended
March 31,
     2013   2012   2013   2012
Location of (Gain) Loss in Income Statement
                                   
Cash Settlements, net of amortization of purchased put premiums:
                                   
Oil sales   $ (1,084 )    $ 3,009     $ (10,455 )    $ 2,576  
Natural gas sales     (2,340 )      (4,128 )      (12,879 )      (23,528 ) 
Total cash settlements     (3,424 )      (1,119 )      (23,334 )      (20,952 ) 
Commodity Derivative Instruments designated as hedging instruments:
                                   
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments     (816 )      3,388       3,800       1,713  
Commodity Derivative Instruments not designated as hedging instruments:
                                   
(Gain) loss on derivative financial instruments
                                   
Realized mark to market (gain) loss     (41 )      23       1,832       (5,001 ) 
Unrealized mark to market (gain) loss     225       84       123       782  
Total (gain) loss on derivative financial instruments     (632 )      3,495       5,755       (2,506 ) 
Total gain   $ (4,056 )    $ 2,376     $ (17,579 )    $ (23,458 ) 

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Derivative Financial Instruments  – (continued)

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

     
Location of (Gain)/Loss   Amount of (Gain) Loss on Derivative Instruments Recognized in
Other
Comprehensive (Income) Loss,
net of tax
(Effective Portion)
  Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss,
net of tax
(Effective Portion)
  Amount of (Gain) Loss on Derivative Instruments Reclassified from Other
Comprehensive (Income) Loss (Ineffective Portion)
Three Months Ended March 31, 2013                           
Commodity Derivative Instruments   $ 5,964                    
Revenues            $ (4,657 )          
(Gain) loss on derivative financial instruments                     $ (816 ) 
Total   $ 5,964     $ (4,657 )    $ (816 ) 
Three Months Ended March 31, 2012                           
Commodity Derivative Instruments   $ 39,757                    
Revenues            $ (1,349 )          
(Gain) loss on derivative financial instruments                     $ 3,388  
Total   $ 39,757     $ (1,349 )    $ 3,388  
Nine Months Ended March 31, 2013                           
Commodity Derivative Instruments   $ 43,482                    
Revenues            $ (18,526 )          
(Gain) loss on derivative financial instruments                     $ 3,800  
Total   $ 43,482     $ (18,526 )    $ 3,800  
Nine Months Ended March 31, 2012                           
Commodity Derivative Instruments   $ (52,837 )                   
Revenues            $ (16,658 )          
(Gain) loss on derivative financial instruments                     $ 1,713  
Total   $ (52,837 )    $ (16,658 )    $ 1,713  

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $15.9 million ($10.3 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position from counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At March 31, 2013, we had no deposits for collateral with our counterparties.

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 10 — Income Taxes

We are a Bermuda company and are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure. We estimate our annual effective tax rate for the current fiscal year and apply it to interim periods. Currently, our estimated annual effective tax rate is approximately 39.5%. The variance from the U.S. statutory rate of 35% is primarily due to the presence of common permanent difference items (such as non-deductible compensation, meals and entertainment expenses) and non-U.S. activity in our Bermuda parent that is ineligible for U.S. tax benefit. Our Bermuda companies continue to report a tax provision reflecting accrued 30% U.S. withholding tax required on any interest (and interest equivalent) payments made from the U.S. companies to the Bermuda companies. We have accrued an additional withholding obligation of $10.4 million for the nine months ended March 31, 2013.

In this quarter, we adjusted our valuation allowance to reflect the annual reconciliation of our U.S. income tax return just filed to our previous estimates. We have a remaining valuation allowance of $30.0 million (related to certain State of Louisiana tax attributes and other property matters). In this quarter, we made a cash withholding tax payment of $3.9 million on outbound accrued intercompany interest paid to Bermuda. This withholding tax was previously accrued and did not result in additional income tax expense being recognized. Similar cash withholding tax payments would be made in the future when additional intercompany interest is paid. While we have not made a cash income tax payment in this quarter, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (AMT) in subsequent quarters may be required (possibly as early as the fourth quarter of fiscal year 2013). At this time, we do not believe the federal estimated income tax payments for this fiscal year will exceed $5 million. We expect this AMT to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.

Note 11 — Stockholders’ Equity

Common Stock

On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, our common stock was admitted for trading on The NASDAQ Global Select Market (“NASDAQ”). Our common stock trades on the NASDAQ and on the Alternative Investment Market of the London Stock Exchange (“AIM”) under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders.

We paid quarterly cash dividends of $0.07 per share to holders of the Company’s common stock for the quarters ended June 30, 2012, September 30, 2012 and December 31, 2012 on September 14, 2012, December 14, 2012 and March 15, 2013 respectively.

On May 1, 2013, our board of directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of the Company’s common stock. The quarterly dividend will be paid on June 14, 2013 to shareholders of record on May 31, 2013.

Preferred Stock

Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. Our board of directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Shares of previously issued preferred stock that have been cancelled are available for future issuance.

Dividends on both the 5.625% Perpetual Convertible Preferred Stock (“5.625% Preferred Stock”) and the 7.25% Perpetual Convertible Preferred Stock (“7.25% Preferred Stock”) are payable quarterly in arrears on each March 15, June 15, September 15 and December 15 of each year.

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 11 — Stockholders’ Equity  – (continued)

Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, shares of the Company’s common stock, or a combination thereof. If the Company elects to make payment in shares of common stock, such shares shall be valued for such purposes at 95% of the market value of the Company’s common stock as determined on the second trading day immediately prior to the record date for such dividend.

Conversion of Preferred Stock

During the nine months ended March 31, 2013, we canceled and converted a total of 929 shares of our 5.625% Preferred Stock into a total of 9,183 shares of common stock using a conversion rate ranging from 9.8578 to 9.899 common shares per preferred share.

Note 12 — Supplemental Cash Flow Information

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

       
  Three Months Ended
March 31,
  Nine Months Ended
March 31,
     2013   2012   2013   2012
Cash paid for interest   $ 3,402     $ 4,698     $ 50,591     $ 56,721  
Cash paid for income taxes     4,056             7,017        

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

       
  Three Months Ended
March 31,
  Nine Months Ended
March 31,
     2013   2012   2013   2012
Financing of insurance premiums   $ (1,266 )    $ (8,558 )    $ (21,131 )    $ (19,215 ) 
Derivative instruments premium financing     12,780       15,557       14,001       12,869  
Preferred stock dividends     (53 )      (138 )      (593 )      (138 ) 
Additions to property and equipment by recognizing asset retirement obligations     1,816       700       11,605       2,037  

Note 13 — Employee Benefit Plans

The Energy XXI Services, LLC 2006 Long-Term Incentive Plan (“Incentive Plan”).  We maintain an incentive and retention program for our employees. Participation shares (“Restricted Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. The Restricted 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 Restricted Stock Units.

Performance Units

For fiscal 2010, 2011 and 2012, we also awarded performance units (“Performance Units”). Of the total Performance Units awarded, 25% are time-based Performance Units (“Time-Based Performance Units”) and 75% are total shareholder return performance-based units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vest equally over a three-year period.

At our discretion, at the time the Restricted Stock Units and Performance Units vest, employees will settle in either common shares or cash. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable.

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 13 — Employee Benefit Plans  – (continued)

Historically, we have paid all Restricted Stock Units vesting awards in cash. Performance Unit awards were paid 50% in common stock and future vesting of the Performance Units may be paid in common stock at the discretion of our board of directors.

We recognized compensation expense related to our outstanding Restricted Stock Units and Performance Units as follows (in thousands):

       
  Three Months Ended
March 31,
  Nine Months Ended
March 31,
     2013   2012   2013   2012
Restricted Stock Units   $ 1,941     $ 6,897     $ 9,668     $ 17,032  
Performance Units     231       10,055       13,086       27,007  
Total compensation expense recognized   $ 2,172     $ 16,952     $ 22,754     $ 44,039  

As of March 31, 2013, we have 886,626 unvested Restricted Stock Units and 5,170,042 unvested Performance Units.

Stock Purchase Plan

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 our common stock that have either been purchased by us on the open market or that have been newly issued by us. During the nine months ended March 31, 2013 and 2012, we issued 208,988 shares and 277,980 shares, respectively, under the 2008 Purchase Plan.

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period. The current offering period is from January 1, 2013 to June 30, 2013. We use Black-Scholes Model to determine fair value, which incorporates assumptions to value stock-based awards. The shares issuable under Employee Stock Purchase Plan are included in calculating diluted earnings per share, if dilutive. The compensation expense recognized and shares issued under Employee Stock Purchase Plan were as follows (in thousands, except for shares):

       
  Three Months Ended
March 31,
  Nine Months Ended
March 31,
     2013   2012   2013   2012
Compensation expense   $ 221     $ 215     $ 598     $ 516  
Shares issued                 27,608       21,015  

Stock Options

In September 2008, our board of directors granted 300,000 stock options to certain officers. These options to purchase our common stock were granted with an exercise price of $17.50 per share. These options vested over a three year period and may be exercised any time prior to September 10, 2018. As of March 31, 2013, 100,000 of the vested options have been exercised and the remaining 200,000 vested options have not been exercised.

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 13 — Employee Benefit Plans  – (continued)

A summary of our stock option activity and related information is as follows:

       
  Nine Months Ended March 31,
     2013   2012
     Shares Under Option   Weighted Ave. Exercise Price   Shares
Under Option
  Weighted
Ave. Exercise
Price
Beginning balance                    100,000     $ 17.50  
Vested                 (100,000 )      17.50  
Ending balance                        

Our net income for the three and nine months ended March 31, 2013 and 2012 includes approximately $0, $0, $0 and $58,000, respectively of compensation costs related to stock options.

We utilize the Black-Scholes model to determine fair value, which incorporates assumptions to value stock-based awards. The dividend yield on our common stock was based on actual dividends paid at the time of the grant. The expected volatility is based on historical volatility of our common stock. The risk-free interest rate is the related United States Treasury yield curve for periods within the expected term of the option at the time of grant.

Defined Contribution Plans

Our employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions that can vary from year to year. We also sponsor a qualified 401(k) Plan that provides for matching. The contributions under these plans were as follows (in thousands):

       
  Three Months Ended
March 31,
  Nine Months Ended
March 31,
     2013   2012   2013   2012
Profit Sharing Plan   $ (481 )    $ (49 )    $ 1,712     $ 1,756  
401(k) Plan     1,587       1,360       2,948       2,866  
Total contributions   $ 1,106     $ 1,311     $ 4,660     $ 4,622  

Note 14 — Related Party Transactions

We have a 20% interest in EXXI M21K and a 49% interest in Ping Energy. We account for these investments using the equity method. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

We are a guarantor of a $100 million line of credit entered into by M21K. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K estimated at $65 million and $1.8 million, respectively. For this guarantee, M21K has agreed to pay us $6.3 million over a period of three years. As of March 31, 2013, we have received $1.2 million related to such guarantee.

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 15 — 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 convertible preferred stock, restricted stock and other common stock equivalents. The following table sets forth the calculation of basic and diluted earnings per share (“EPS”) (in thousands, except per share data):

       
  Three Months Ended
March 31,
  Nine Months Ended
March 31,
     2013   2012   2013   2012
Net income   $ 40,436     $ 91,252     $ 100,028     $ 254,672  
Preferred stock dividends     2,873       2,739       8,623       10,151  
Induced Conversion of Preferred Stock           6,058             6,058  
Net income available for common stockholders   $ 37,563     $ 82,455     $ 91,405     $ 238,463  
Weighted average shares outstanding for basic EPS     79,365       77,454       79,280       76,803  
Add dilutive securities     8,151       9,899       8,191       10,382  
Weighted average shares outstanding for
diluted EPS
    87,516       87,353       87,471       87,185  
Earnings per share
                                   
Basic   $ 0.47     $ 1.06     $ 1.15     $ 3.10  
Diluted   $ 0.46     $ 1.04     $ 1.14     $ 2.92  

Note 16 — Commitments and Contingencies

Litigation.  We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.

Lease Commitments.  We have a non-cancelable operating lease for office space and other that expires on March 31, 2018. Future minimum lease commitments as of March 31, 2013 under the operating lease are as follows (in thousands):

 
Twelve Months Ended March 31,
 
2014   $ 2,821  
2015     2,980  
2016     2,776  
2017     2,849  
2018     2,559  
Thereafter     1,936  
Total   $ 15,921  

Rent expense, including rent incurred on short-term leases, for the three months ended March 31, 2013 and 2012 was $861,000 and $942,000, respectively, and for the nine months ended March 31, 2013 and 2012 was $2,122,000 and $1,839,000, respectively.

Letters of Credit and Performance Bonds.  We had $225.3 million in letters of credit and $44.4 million of performance bonds outstanding as of March 31, 2013.

Line of Credit.  Our equity method investee, EXXI M21K, of which we own 20%, is a guarantor of a $100 million line of credit entered into by M21K on February 23, 2012. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 16 — Commitments and Contingencies  – (continued)

Guarantee.   We are a guarantor of a $100 million line of credit entered into by M21K. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report. We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K estimated at $65 million and $1.8 million, respectively. For this guarantee, M21K has agreed to pay us $6.3 million over a period of three years. See Note 14 — Related Party Transactions of Notes to Consolidated Financial Statements in this Quarterly Report.

Drilling Rig Commitments.  As of March 31, 2013, we have entered into seven drilling rig commitments:

1) January 16, 2013 to June 30, 2013 at $49,000 per day

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

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

4) March 5, 2013 to September 5, 2013 at $130,000 per day

5) October 2, 2012 to June 1, 2013 at $90,000 per day

6) February 15, 2013 to July 15, 2013 at $39,000 per day

7) March 15, 2013 to July 1, 2013 at $36,000 per day

At March 31, 2013, future minimum commitments under these contracts totaled $70.2 million.

Note 17 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

The carrying amounts approximate fair value for cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable due to the short-term nature or maturity of the instruments.

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

The fair values of our stock based units are based on period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model are used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on TSR Performance-Based Units valuation.

Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 17 — Fair Value of Financial Instruments  – (continued)

(or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

Level 1 — quoted prices in active markets for identical assets or liabilities.
Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).
Level 3 — unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

       
  Level 1   Level 2
     March 31, 2013   June 30,
2012
  March 31, 2013   June 30,
2012
Assets:
                                   
Oil and natural gas derivatives               $ 85,467     $ 170,955  
Liabilities:
                                   
Oil and natural gas derivatives                     $ 45,106     $ 92,962  
Restricted stock units   $ 6,964     $ 15,124                    
Time-based performance units     2,397       4,434                    
Total liabilities   $ 9,361     $ 19,558     $ 45,106     $ 92,962  

The following table describes the changes to our Level 3 financial instruments (in thousands):

   
  Level 3
     Nine Months Ended March 31,
     2013   2012
Liabilities:
                 
Performance-based performance units
                 
Balance at beginning of period   $ 22,855     $ 20,305  
Vested     (23,161 )      (23,807 ) 
Grants and changes in fair value charged to general and
administrative expense
    10,264       23,320  
Balance at end of period   $ 9,958     $ 19,818  

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 18 — Prepayments and Accrued Liabilities

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

   
  March 31, 2013   June 30,
2012
Prepaid expenses and other current assets
                 
Advances to joint interest partners   $ 3,059     $ 12,966  
Insurance     6,801       30,515  
Inventory     4,127       4,849  
Royalty deposit     1,961       2,443  
Short-term stock investment     23       8,786  
Other     6,823       3,470  
Total prepaid expenses and other current assets   $ 22,794     $ 63,029  
Accrued liabilities
                 
Advances from joint interest partners   $ 10,264     $ 301  
Employee benefits and payroll     29,132       53,541  
Interest     28,037       3,721  
Accrued hedge payable     4,228       136  
Undistributed oil and gas proceeds     46,757       54,484  
Other     3,146       6,635  
Total accrued liabilities   $ 121,564     $ 118,818  

Note 19 — Subsequent Events

EGC entered into the Fourth and Fifth Amendments to the First Lien Credit Agreement on April 9, 2013 and May 1, 2013, respectively. See Note 6 — Long-Term Debt of Notes to Consolidated Financial Statements in this Quarterly Report.

On April 9, 2013, M21K entered into the Third Amendment to the M21K First Lien Credit Agreement. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

On May 1, 2013, our board of directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of the Company’s common stock. The quarterly dividend will be paid on June 14, 2013 to shareholders of record on May 31, 2013.

On May 1, 2013, our Board of Directors approved a stock repurchase program authorizing Energy XXI, Inc., a Delaware subsidiary of the Company (“Energy XXI, Inc.”), to repurchase up to $250 million in value of the Company’s common stock for an extended period of time, in one or more open market transactions. The Company also announced that in connection with the repurchase program, the Board of Directors has also approved a 10b5-1 plan, allowing Energy XXI, Inc. to repurchase the Company’s shares at times when it otherwise might be prevented from doing so under insider trading laws or because of self-imposed trading blackout periods. Energy XXI, Inc. intends to fund the share repurchases through borrowings under EGC’s revolving credit facility and repurchased shares will be retained by Energy XXI, Inc., subject to transfer to the Company where they may be retired. Such authorized repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity.

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ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are an independent oil and natural gas exploration and production company with properties focused in the U.S. Gulf Coast and the Gulf of Mexico. Our business strategy includes: (1) acquiring producing oil and gas properties; (2) exploiting and exploring our core assets to enhance production and ultimate recovery of reserves; and (3) utilizing a portion of our capital program to explore the ultra-deep trend for potential oil and gas reserves. We are one of the largest oil producers on the Gulf of Mexico shelf with interest in six of the eleven largest oil fields on the Gulf of Mexico shelf.

Our operations are geographically focused, and we target acquisitions of oil and gas properties to 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. For the year ended June 30, 2012, excluding acquisitions, approximately 33% of our capital expenditures were associated with the exploitation of existing properties.

At June 30, 2012, our total proved reserves were 119.6 MMBOE of which 71% were oil and 68% were classified as proved developed and we operated or had an interest in 450 gross producing wells on 239,502 net developed acres, including interests in 41 producing fields. All of our properties are primarily located on the U.S. Gulf Coast and in the Gulf of Mexico, with approximately 91% of our proved reserves being offshore. This concentration facilitates our ability to manage the operated fields efficiently, and our high number of wellbore locations provides diversification of our production and reserves. We believe operating our assets is key to our strategy, and approximately 85% of our proved reserves are on properties operated by us. We have a seismic database covering approximately 5,670 square miles, primarily focused on our existing operations. This database has helped us identify approximately 194 drilling opportunities. We believe the mature legacy fields on our acquired properties will lend themselves well to our aggressive exploitation strategy, and we expect to identify incremental exploration opportunities on the properties.

We are actively engaged in a program designed to manage our commodity price risk, and we seek to hedge the majority of our proved developed producing reserves to enhance cash flow certainty and predictability. In connection with our acquisitions, we typically enter into hedging arrangements to minimize commodity downside exposure. We believe our disciplined risk management strategy provides substantial price protection, as our cash flow on the hedged portion is driven by production results rather than commodity prices. We believe this greater price certainty allows us to more efficiently manage our cash flows and allocate our capital resources.

Outlook

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. Multiple events during 2009 through 2012 involving numerous countries and financial institutions and the market, in general, impacted liquidity within the capital markets throughout the United States and around the world. Despite efforts by the U.S. Treasury Department and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector, capital markets remain constrained. As a result, we expect that our ability to raise debt and equity and the terms on which we can raise capital will be dependent upon the condition of the capital markets.

Although we currently expect to fund our capital program from existing cash flow from operations, these cash flows are dependent upon future production volumes and commodity prices. Maintaining adequate liquidity may involve the issuance of additional debt and equity at less attractive terms, or the sale of assets and could require reductions in our capital spending. In the near-term we will focus on maximizing returns on existing assets by selectively deploying capital to improve existing production and pursuing our ultra-deep shelf exploration program.

Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. As required by our revolving credit facility, we have mitigated this

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volatility through December 2015 by implementing a hedging program on a portion of our total anticipated production during this time frame. See Note 9 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

We are also subject to natural gas and oil production declines. We attempt to replace this declining production through our drilling and recompletion program and acquisitions. We will maintain our focus on controlling costs to add reserves through drilling and acquisitions, as well as controlling the corresponding costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability to timely obtain drilling permits and regulatory approvals and voluntary reductions in capital spending in a low commodity price environment. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of our production, which may have an adverse effect on our revenues. Consistent with our business strategy, we intend to invest the capital necessary to maintain our production at existing levels over the long-term provided that it is economical to do so based on the commodity price environment. However, we cannot be certain that we will be able to issue additional debt and equity on acceptable terms, or at all, and we may be unable to refinance our revolving credit facility when it expires. Additionally, should commodity prices decline, our borrowing base under our revolving credit facility may be reduced thereby eliminating the working capital necessary to fund our capital spending program as well as potentially requiring us to repay certain of our outstanding indebtedness. The explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico, as well as the resulting oil spill, have also led to increased governmental regulation of our and our industry’s operations in a number of areas, including health and safety, environmental, and licensing, any of which could result in increased costs or delays in our current and future drilling operations.

Operational Highlights

Ultra-Deep Shelf Exploration and Development Activity

We participate with McMoRan Exploration Company in several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico. Data received to date from ultra-deep shelf drilling with respect to the Davy Jones and Blackbeard West discovery wells in the Gulf of Mexico confirm geologic modeling that correlates objective sections on the shelf below the salt weld in the Miocene and older age sections to those productive sections seen in deepwater discoveries by other industry participants. In addition to Davy Jones and Blackbeard West, we have also identified approximately 15 ultra-deep prospects in shallow water near existing infrastructure. In addition, we will participate in three onshore ultra-deep prospects located in South Louisiana. The ultra-deep drilling plans in calendar years 2008 through 2013 included the Blackbeard East, Lafitte, Blackbeard West, Lomond North, Blackbeard West No. 2 and Lineham Creek exploratory wells and delineation drilling at Davy Jones. Near term sub-salt drilling plans include 2 to 3 exploratory wells. We expect to have more than sufficient liquidity to fund our current commitments related to our ultra-deep trend exploration and development activity.

As previously reported, we have drilled two successful sub-salt wells in the Davy Jones field. The Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. The Davy Jones offset appraisal well (Davy Jones No. 2), which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect, and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. The Davy Jones field involves a large ultra-deep structure encompassing four Outer Continental shelf lease blocks (20,000 acres). As of March 31, 2013, our investment in both wells in the Davy Jones field totaled approximately $148 million.

Davy Jones.  The Davy Jones No. 1 well on South Marsh Island Block 230 was successfully completed in March 2012. The perforation of the Wilcox “D” sand in March 2012 resulted in positive pressure build-up in the wellbore followed by a gas flare from the well. Initial samples indicated that the natural gas from the Wilcox “D” sand is high quality and contains low levels of CO2 and no H2S is present. Blockage from drilling fluid associated with initial drilling operations prevented the group from obtaining a measurable flow rate. During early January, the operator reperforated the Wilcox zones in the well with through-tubing perforating guns. Recent operations confirm that the perforations are open and that fluid could be injected through the perforations into the formation. The operator has moved the rig off location while a large-scale hydraulic fracture treatment is designed and results at Lineham Creek studied to decide further operation.

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Blackbeard East.  The Blackbeard East ultra-deep exploration by-pass well was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. The Frio sands are the first hydrocarbon bearing Frio sands encountered either on the Gulf of Mexico shelf or in the deepwater offshore Louisiana. Pressure and temperature data below the salt weld between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. The operator held the lease rights to South Timbalier Block 144 through August 17, 2012 and during the quarter submitted initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement (“BSEE”). The operator plans to test and complete the upper Miocene sands during 2013 using conventional equipment and technologies. Additional plans for further development of the deeper zones continue to be evaluated. The group’s ability to preserve the interest in Blackbeard East will require approval from the BSEE of the development plans. Blackbeard East is located in 80 feet of water on South Timbalier Block 144. As of March 31, 2013, our investment in the well totaled approximately $51 million.

Lafitte.  The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Vicksburg, and Sparta carbonate. The Upper Eocene sands are the first hydrocarbon bearing Upper Eocene sands encountered either on the Gulf of Mexico shelf or in the deepwater offshore Louisiana. The group is evaluating development options associated with these formations. In October 2012, the operator submitted initial development plans to complete and test the Jackson/Yegua sands in the Upper Eocene with the BSEE. As of March 31, 2013, our investment in the well totaled approximately $40 million.

Blackbeard West.  Information gained from the Blackbeard East and Lafitte wells will enable us to consider priorities for future operations at Blackbeard West. As previously reported, the Blackbeard West ultra-deep exploratory well on South Timbalier Block 168 was drilled to 32,997 feet in 2008. Logs indicated four potential hydrocarbon bearing zones that require further evaluation, and the well was temporarily abandoned. The Blackbeard West No. 2 ultra-deep exploration well commenced drilling on November 25, 2011 and reached total depth of 25,584 feet in January 2013. Initial completion efforts are expected to focus on the development of laminated sands in the Middle Miocene located at approximately 24,000 feet. Through logs and core data, the operator has identified three potential hydrocarbon bearing Miocene sand sections between approximately 20,800 and 24,000 feet. Initial completion efforts are expected to focus on the development of approximately 50 net feet of laminated sands in the Middle Miocene located at approximately 24,000 feet. Additional development opportunities in the well bore include approximately 80 net feet of potential low-resistivity pay at approximately 22,400 feet and an approximate 75 foot gross section at approximately 20,900 feet. Pressure and temperature data indicate that a completion at these depths could utilize conventional equipment and technologies. Our investment in both Blackbeard West wells totaled approximately $57 million at March 31, 2013.

Lineham Creek.  The Lineham Creek exploration prospect, operated by Chevron U.S.A. Inc., which is located onshore in Cameron Parish, Louisiana commenced drilling on March 31, 2011. The well, which is targeting Eocene and Paleocene objectives below the salt weld, is currently drilling below 29,400 feet towards a proposed total depth of 30,500 feet. The well encountered positive results above 24,000 feet in November 2012. Detailed whole core and log data obtained will be used in evaluating future plans for all ultra-deep wells. As of March 31, 2013, our investment in the Lineham Creek well totaled approximately $16 million.

Lomond North.  The Lomond North exploration prospect in the Highlander area where multiple high potential prospects on an 80,000 acre position have been identified is operated by McMoRan Exploration Company. The well, which is located onshore in St. Martin Parish, Louisiana, commenced drilling on September 19, 2012. The well, which is targeting Eocene, Creataceous and Paleocene objectives below the salt weld, is currently drilling below 18,250 feet towards a proposed total depth of 30,000 feet. As of March 31, 2013, our investment in the Lomond North well totaled approximately $15 million.

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Known Trends and Uncertainties

Continued Volatility in Commodity Price Environment.  Commodity prices are one of our key drivers of earnings generation and net operating cash flow and are affected by many factors that are outside of our control. Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. We actively seek to mitigate this volatility through the implementation of a hedging program that covers a portion of our total anticipated production through December 2015. See Note 9 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report for a detailed discussion of our hedging program.

Ongoing Disruptions in Global Financial Markets.  Multiple events during 2009 through 2012 involving numerous countries and financial institutions impacted liquidity within the capital markets throughout the United States and around the world. Despite efforts by the U.S. Treasury Department and banking regulators in the United States, Europe and other nations around the world to provide liquidity and stability to the financial sector, access to capital markets has remained somewhat constrained. While we currently expect to fund our capital program from existing cash flow from operations, we may be required to issue equity or debt to maintain adequate liquidity to implement our capital program. To extent that access to capital markets remains constrained, we expect that our ability to raise debt and equity capital, and the terms on which we can raise such capital, may be somewhat restricted.

Oil Spill Response Plan.  We maintain a Regional Oil Spill Response Plan (the “Plan”) that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are generally approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. We believe the Plan specifications are consistent with the requirements set forth by the BSEE. Additionally, these plans are tested and drills are conducted periodically at all levels of the Company.

The Company has contracted with an emergency and spill response management consultant, to provide management expertise, personnel and equipment, under the supervision of the Company, in the event of an incident requiring a coordinated response. Additionally, the Company is a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the GOM and has capabilities to simultaneously respond to multiple spills. CGA has chartered its marine equipment to the Marine Spill Response Corporation (“MSRC”), a private, not-for-profit marine spill response organization which is funded by the Marine Preservation Association, a member-supported, not-for-profit organization created to assist the petroleum and energy-related industries by addressing problems caused by oil spills on water. In the event of a spill, MSRC mobilizes appropriate equipment to CGA members. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies.

Hurricanes.  Since the majority of our production originates in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes is becoming more difficult to obtain. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs. During the nine months ended March 31, 2013 we were impacted by Hurricane Isaac which resulted in weather related downtime on properties where we have an interest. Additionally, there was no material damage to any assets or company property.

Ultra-Deep Trend Exploration and Development.  We have participated in eight ultra-deep wells to date. Of these wells, one has been temporarily abandoned pending further evaluation, four are temporarily abandoned pending facilities and completions, two are currently drilling and one is currently being tested. These projects have similar geological characteristics as deepwater prospects with a potential for significant reserves. The shallow water ultra-deep trend wells are some of the deepest wells ever drilled in the world and are subject to very high pressures and temperatures. The drilling, logging and completion techniques are near the limits of existing technologies. As a result, new technologies and techniques are being developed to deal

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with these challenges. The use of advanced drilling technologies involves a higher risk of technological failure and potentially higher costs. In addition, there can be delays in completion due to necessary equipment that is specially ordered to handle the challenges of ultra-deep wells. The shallow water ultra-deep is considered in the industry as Ultra High Pressure High Temperature (“U-HPHT”). Generally this refers to pressures above 15,000 psig and temperatures above 300°F. The U-HPHT in the play range from 400°F to 474°F and bottom hole pressures from 26,500 psig to over 30,000 psig. Completion equipment has been designed to handle surface pressures to 25,000 psig and have been tested to 37,500 psig. There were 18 new technologies developed for this project which went through extensive design reviews, computational analysis and finally physical testing to meet requirements for use in U-HPHT wells. All equipment is currently qualified to 25,000 psig and 450°F. Work is ongoing for qualifying some of the same equipment for 30,000 psig surface. We target to spend less than 10% of our budgeted cash flow on our exploration activities on the ultra-deep. Based on the results of these wells, our proved reserves may vary from our current 71% oil composition.

Operational Information (In thousands except for unit amounts)

         
  Quarter Ended
     Mar. 31, 2013   Dec. 31, 2012   Sept. 30, 2012   June 30, 2012   Mar. 31,
2012
Operating Highlights
                                            
Operating revenues
                                            
Crude oil sales   $ 273,280     $ 280,953     $ 242,830     $ 314,639     $ 315,723  
Natural gas sales     27,070       29,657       17,396       19,657       19,154  
Hedge gain     3,424       9,909       10,001       7,650       1,119  
Total revenues     303,774       320,519       270,227       341,946       335,996  
Percent of operating revenues from crude oil
                                            
Prior to hedge gain     91 %      90 %      93 %      94 %      94 % 
Including hedge gain     90 %      89 %      92 %      92 %      93 % 
Operating expenses
                                            
Lease operating expense
                                            
Insurance expense     7,473       8,810       8,992       6,825       7,138  
Workover and maintenance     19,166       20,217       10,113       21,070       15,885  
Direct lease operating expense     59,666       56,895       63,376       59,306       55,424  
Total lease operating expense     86,305       85,922       82,481       87,201       78,447  
Production taxes     1,352       1,166       1,247       2,414       1,499  
Gathering and transportation     4,411       6,098       7,991       4,358       2,465  
DD&A     88,727       105,856       84,795       106,644       88,448  
General and administrative     16,092       19,319       23,888       19,733       25,075  
Other – net     7,017       8,621       13,174       5,186       13,257  
Total operating expenses     203,904       226,982       213,576       225,536       209,191  
Operating income   $ 99,870     $ 93,537     $ 56,651     $ 116,410     $ 126,805  
Sales volumes per day
                                            
Natural gas (MMcf)     89.4       90.9       67.1       92.5       83.7  
Crude oil (MBbls)     28.6       29.4       26.1       32.2       31.4           
Total (MBOE)     43.5       44.6       37.3       47.6       45.3  
Percent of sales volumes from crude oil     66 %      66 %      70 %      68 %      69%  

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  Quarter Ended
     Mar. 31, 2013   Dec. 31, 2012   Sept. 30, 2012   June 30, 2012   Mar. 31,
2012
Average sales price
                                            
Natural gas per Mcf   $ 3.37     $ 3.55     $ 2.82     $ 2.34     $ 2.52  
Hedge gain per Mcf     0.29       0.60       0.89       0.55       0.54  
Total natural gas per Mcf   $ 3.66     $ 4.15     $ 3.71     $ 2.89     $ 3.06  
Crude oil per Bbl   $ 106.11     $ 103.79     $ 101.03     $ 107.34     $ 110.54  
Hedge gain (loss) per Bbl     0.42       1.80       1.87       1.03       (1.05 ) 
Total crude oil per Bbl   $ 106.53     $ 105.59     $ 102.90     $ 108.37     $ 109.49  
Total hedge gain per BOE   $ 0.87     $ 2.42     $ 2.91     $ 1.77     $ 0.27  
Operating revenues per BOE   $ 77.58     $ 78.15     $ 78.72     $ 78.90     $ 81.43  
Operating expenses per BOE
                                            
Lease operating expense
                                            
Insurance expense     1.91       2.15       2.62       1.57       1.73  
Workover and maintenance     4.89       4.93       2.95       4.86       3.85  
Direct lease operating expense     15.24       13.87       18.46       13.68       13.43  
Total lease operating expense     22.04       20.95       24.03       20.11       19.01  
Production taxes     0.35       .28       0.36       0.56       0.36  
Gathering and transportation     1.13       1.49       2.33       1.01       0.60  
DD&A     22.66       25.81       24.70       24.61       21.44  
General and administrative     4.11       4.71       6.96       4.55