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

 

FORM 10-Q

 

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

For the quarterly period ended March 31, 2012

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 x 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 x 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 x		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 x

As of April 26, 2012, there were 78,872,346 shares outstanding of the registrant’s common stock, par value $0.005 per share.

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ENERGY XXI (BERMUDA) LIMITED
  
TABLE OF CONTENTS

		Page
GLOSSARY OF TERMS			1
PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements			5
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			37
ITEM 4. Controls and Procedures			39
PART II — OTHER INFORMATION
ITEM 1. Legal Proceedings			40
ITEM 1A. Risk Factors			40
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			40
ITEM 3. Defaults upon Senior Securities			40
ITEM 4. Mine Safety Disclosures			40
ITEM 5. Other Information			40
ITEM 6. Exhibits			41
SIGNATURES			42
EXHIBIT INDEX			43

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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 (this “Quarterly Report”):

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. 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

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) for this call option.

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 installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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 a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension 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)(15) 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.

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) for this put option.

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’s subsurface 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.

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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 intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

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 undeveloped oil and gas reserves, refer to Rule 4-10(a)(31) of Regulation S-X as promulgated by the SEC.

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:

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 report and (2) Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2011, as amended (the “2011 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, 2012				June 30, 2011
		(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents		$	85,524			$	28,407
Accounts receivable
Oil and natural gas sales			152,238				126,194
Joint interest billings			3,309				4,526
Insurance and other			2,732				2,533
Prepaid expenses and other current assets			42,755				47,751
Derivative financial instruments			2,541				22
Total Current Assets			289,099				209,433
Property and Equipment
Oil and natural gas properties – full cost method of accounting, including $523.4 million and $467.3 million of unevaluated properties at March 31, 2012 and June 30, 2011, respectively			2,675,870				2,545,336
Other property and equipment			9,701				8,201
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment			2,685,571				2,553,537
Other Assets
Derivative financial instruments			15,228				—
Deferred income taxes			—				2,411
Debt issuance costs, net of accumulated amortization			29,066				33,479
Total Other Assets			44,294				35,890
Total Assets		$	3,018,964			$	2,798,860
LIABILITIES
Current Liabilities
Accounts payable		$	154,963			$	163,741
Accrued liabilities			102,842				111,157
Notes payable			638				19,853
Asset retirement obligations			24,989				19,624
Derivative financial instruments			54,054				50,259
Current maturities of long-term debt			3,429				4,054
Total Current Liabilities			340,915				368,688
Long-term debt, less current maturities			1,015,392				1,109,333
Deferred income taxes			56,078				—
Asset retirement obligations			322,980				303,618
Derivative financial instruments			14,872				70,524
Other liabilities			10,257				—
Total Liabilities			1,760,494				1,852,163
Commitments and Contingencies (Note 14)
Stockholders’ Equity
Preferred stock, $0.001 par value, 7,500,000 and 2,500,000 shares authorized at March 31, 2012 and June 30, 2011, respectively:
7.25% Convertible perpetual preferred stock, 8,000 shares issued and outstanding at March 31, 2012 and June 30, 2011, respectively			—				—
5.625% Convertible perpetual preferred stock, 814,220 and 1,050,000 shares issued and outstanding at March 31, 2012 and June 30, 2011, respectively			1				1
Common stock, $0.005 par value, 200,000,000 shares authorized and 79,114,643 and 76,203,574 shares issued and 78,879,124 and 76,202,921 shares outstanding at March 31, 2012 and June 30, 2011, respectively			394				381
Additional paid-in capital			1,500,419				1,479,959
Accumulated deficit			(226,697	)			(465,160	)
Accumulated other comprehensive loss, net of income taxes			(15,647	)			(68,484	)
Total Stockholders’ Equity			1,258,470				946,697
Total Liabilities and Stockholders’ Equity		$	3,018,964			$	2,798,860

 
 
See accompanying Notes to Consolidated Financial Statements

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

		Three Months Ended March 31,								Nine Months Ended March 31,
		2012				2011				2012				2011
Revenues
Oil sales		$	312,714			$	216,711			$	868,978			$	479,080
Natural gas sales			23,282				41,925				92,479				97,509
Total Revenues			335,996				258,636				961,457				576,589
Costs and Expenses
Lease operating			78,447				65,257				223,614				153,856
Production taxes			1,499				721				4,847				2,131
Gathering and transportation			2,465				4,809				12,013				5,631
Depreciation, depletion and amortization			88,448				91,301				260,819				208,300
Accretion of asset retirement obligations			9,762				9,907				29,253				22,229
General and administrative			25,075				23,155				66,543				57,538
Loss (gain) on derivative financial instruments			3,495				(619	)			(2,506	)			(3,395	)
Total Costs and Expenses			209,191				194,531				594,583				446,290
Operating Income			126,805				64,105				366,874				130,299
Other Income (Expense)
Bridge loan commitment fees			—				—				—				(4,500	)
Loss on retirement of debt			—				(12,199	)			—				(17,383	)
Other income			97				15				121				176
Interest expense			(26,887	)			(31,418	)			(82,438	)			(74,992	)
Total Other Expense			(26,790	)			(43,602	)			(82,317	)			(96,699	)
Income Before Income Taxes			100,015				20,503				284,557				33,600
Income Tax Expense			8,763				2,132				29,885				4,162
Net Income			91,252				18,371				254,672				29,438
Induced Conversion of Preferred Stock			6,058				44				6,058				19,840
Preferred Stock Dividends			2,739				4,278				10,151				8,698
Net Income Attributable to Common Stockholders		$	82,455			$	14,049			$	238,463			$	900
Net Income Per Share Attributable to Common Stockholders
Basic		$	1.06			$	0.19			$	3.10			$	0.01
Diluted		$	1.04			$	0.19			$	2.92			$	0.01
Weighted Average Number of Common Shares Outstanding
Basic			77,454				74,221				76,803				63,490
Diluted			87,353				74,421				87,185				63,732

 
 
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,
		2012				2011				2012				2011
Cash Flows From Operating Activities
Net income		$	91,252			$	18,371			$	254,672			$	29,438
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			88,448				91,301				260,819				208,300
Deferred income tax expense			8,764				2,132				30,036				4,162
Change in derivative financial instruments
Proceeds from sale of derivative instruments			993				—				66,522				42,577
Other – net			(10,866	)			(9,773	)			(36,557	)			(25,987	)
Accretion of asset retirement obligations			9,762				9,907				29,253				22,229
Amortization of debt discount and premium			—				(389	)			—				(43,521	)
Amortization and write-off of debt issuance costs			1,886				6,568				5,591				10,822
Stock-based compensation			478				946				10,592				3,126
Payment of interest in-kind			—				—				—				2,225
Changes in operating assets and liabilities
Accounts receivable			(9,565	)			(14,732	)			(27,146	)			(54,703	)
Prepaid expenses and other current assets			9,945				10,717				4,879				8,439
Settlement of asset retirement obligations			(4,569	)			(19,537	)			(6,563	)			(54,155	)
Accounts payable and accrued liabilities			11,670				50,744				(25,916	)			70,756
Net Cash Provided by Operating Activities			198,198				146,255				566,182				223,708
Cash Flows from Investing Activities
Acquisitions			(35	)			(9,113	)			(6,212	)			(1,022,124	)
Capital expenditures			(155,744	)			(61,571	)			(394,188	)			(190,196	)
Insurance payments received							—				6,472				—
Proceeds from the sale of properties			203				75				2,970				475
Other			1,252				(52	)			444				31
Net Cash Used in Investing Activities			(154,324	)			(70,661	)			(390,514	)			(1,211,814	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs			191				1,187				9,647				562,090
Conversion of preferred stock to common			(6,029	)			(44	)			(6,029	)			(11,956	)
Dividends to shareholders			(2,877	)			(6,153	)			(10,289	)			(8,326	)
Proceeds from long-term debt			185,437				378,526				707,761				1,538,526
Payments on long-term debt			(214,468	)			(458,084	)			(818,787	)			(1,044,851	)
Payments for debt issuance costs and other			—				2,089				(854	)			(28,495	)
Net Cash Provided by (Used in) Financing Activities			(37,746	)			(82,479	)			(118,551	)			1,006,988
Net Increase (Decrease) in Cash and Cash Equivalents			6,128				(6,885	)			57,117				18,882
Cash and Cash Equivalents, beginning of period			79,396				39,991				28,407				14,224
Cash and Cash Equivalents, end of period		$	85,524			$	33,106			$	85,524			$	33,106

 
 
See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 — Recent Accounting Pronouncements  – (continued)

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 and results of operations.

Note 3 — Acquisitions and Dispositions

ExxonMobil Acquisition

On December 17, 2010, we closed on the acquisition of certain shallow-water Gulf of Mexico shelf oil and natural gas interests (the “ExxonMobil Properties”) from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”). The ExxonMobil Acquisition was funded through a combination of cash on hand, including proceeds from common and preferred equity offerings (see “Note 10 — Stockholders’ Equity”), borrowings under our revolving credit facility and proceeds from the $750 million private placement by our indirect, wholly owned operating subsidiary, Energy XXI Gulf Coast, Inc. (“EGC”), of 9.25% Senior Notes.

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

The ExxonMobil Acquisition was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred.

As of December 31, 2011, the Company’s measurement period adjustments were complete. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 17, 2010 ( in thousands ):

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

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

Sale of Certain Onshore Properties

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

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

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

Note 4 — Property and Equipment

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

		March 31, 2012				June 30, 2011
Oil and natural gas properties
Proved properties		$	4,143,440			$	3,810,293
Less: Accumulated depreciation, depletion, amortization and impairment			1,990,942				1,732,250
Proved properties			2,152,498				2,078,043
Unproved properties			523,372				467,293
Oil and natural gas properties			2,675,870				2,545,336
Other property and equipment			21,860				18,354
Less: Accumulated depreciation			12,159				10,153
Other property and equipment			9,701				8,201
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment		$	2,685,571			$	2,553,537

Note 5 — Long-Term Debt

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

		March 31, 2012				June 30, 2011
Revolving credit facility		$	—			$	107,784
9.25% Senior Notes due 2017			750,000				750,000
7.75% Senior Notes due 2019			250,000				250,000
Derivative instruments premium financing			17,842				4,926
Capital lease obligation			979				677
Total debt			1,018,821				1,113,387
Less current maturities			3,429				4,054
Total long-term debt		$	1,015,392			$	1,109,333

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Long-Term Debt  – (continued)

Maturities of long-term debt as of March 31, 2012 are as follows ( in thousands ):

Twelve Months Ending March 31,
2013		$	3,429
2014			6,904
2015			8,488
2016			—
2017			—
Thereafter			1,000,000
Total		$	1,018,821

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, EGC in May 2011. This facility has a borrowing capacity of $925 million and matures December 31, 2014. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. At March 31, 2012, the current borrowing base was $750 million, which was unanimously reaffirmed by the lenders on September 14, 2011. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.25% to 3.00% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves.

EGC is prohibited from paying dividends to us except that EGC may make payments to us of up to $25 million in aggregate (including those in the aggregate total amount of $11,082,156 made to date) for the purpose of paying premiums or other payments associated with the early conversion of our preferred stock and EGC may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock. On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement which provided for increased flexibility to pay dividends or make loans from EGC to us and/or our other subsidiaries. The First Amendment modified the First Lien Credit Agreement and includes the following: (a) approval for cash distributions of up to $100 million per calendar year, which can be used for various purposes, including stock buybacks, bond repurchases, and /or debt repayments, and is based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds, and (b) approval of a cash distribution basket of up to an aggregate of $150 million, to be used for investments and other purposes based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds. Both distribution baskets are further limited by an amount equal to $70 million plus 50% of our Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter.

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

The First Lien Credit Agreement 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, 2012, we were in compliance with all covenants under our First Lien Credit Agreement.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Long-Term Debt  – (continued)

High Yield Facilities

9.25% Senior Notes

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

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

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of March 31, 2012 was $821 million based on quoted prices and the market is not an active market, therefore, the fair value is classified within level 2.

7.75% Senior Notes

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

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

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of March 31, 2012 was $257 million based on quoted prices and the market is not an active market, therefore, the fair value is classified within level 2.

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, 2012 and June 30, 2011, our outstanding derivative instruments premium financing totaled $17.8 million and $4.9 million, respectively.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Long-Term Debt  – (continued)

Interest Expense

For the three months and nine months ended March 31, 2012 and 2011, interest expense consisted of the following ( in thousands ):

		Three Months Ended March 31,								Nine Months Ended March 31,
		2012				2011				2012				2011
Revolving credit facility		$	2,201			$	4,243			$	7,291			$	7,140
9.25% Senior Notes due 2017			17,344				17,344				52,031				19,849
7.75% Senior Notes due 2019			4,843				1,776				14,531				1,776
10% Senior Notes due 2013			—				4,770				—				18,595
16% Second Lien Notes due 2014			—				—				—				24,967
Amortization of debt issue cost – Revolving credit facility			1,238				2,174				3,645				4,699
Amortization of debt issue cost –  10% Senior Notes due 2013			—				314				—				1,492
Amortization of debt issue cost –  16% Second Lien Notes due 2014			—				—				—				54
Amortization of debt issue cost –  9.25% Senior Notes due 2017			552				552				1,655				644
Amortization of debt issue cost –  7.75% Senior Notes due 2019			97				45				291				45
Discount amortization – 16% Second Lien Notes due 2014 (Private Placement)			—				—				—				1,894
Premium amortization – 16% Second Lien Notes due 2014 (Exchange Offer)			—				—				—				(6,889	)
Derivative instruments premium financing and other			612				200				1,104				726
Settlement of Lehman Brothers liability			—				—				1,890				—
		$	26,887			$	31,418			$	82,438			$	74,992

Bridge Loan Commitment Fee

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

Note 6 — Notes Payable

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

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Notes Payable  – (continued)

In July 2011, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note is for a total face amount of $6.3 million and bears interest at an annual rate of 1.93%. The note amortizes over the remaining term of the insurance, which matures May 1, 2012. The balance outstanding as of March 31, 2012 was $0.6 million.

Note 7 — Asset Retirement Obligations

Changes in asset retirement obligations were as follows ( in thousands ):

Balance at June 30, 2011		$	323,242
Liabilities acquired			125
Liabilities incurred			1,912
Liabilities settled			(6,563	)
Accretion expense			29,253
Total balance at March 31, 2012			347,969
Less current portion			24,989
Long-term balance at March 31, 2012		$	322,980

Note 8 — 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. The Company designates a majority of its derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled.

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

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX, ICE) plus the difference between the purchased put and the sold put strike price.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 — Derivative Financial Instruments  – (continued)

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we have utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. Historically the basis differential between HLS and WTI has been relatively small and predictable. Over the past five years, HLS has averaged approximately $1 per barrel premium to WTI. Since the beginning of 2011, the HLS/WTI basis differential and volatility has increased with HLS carrying as much as a $30 per barrel premium to WTI. During the quarter ended September 30, 2011, the Company began 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 and received the following cash proceeds in the following quarters ( in thousands ):

Quarter Ended		Cash Proceeds
March 31, 2009		$	66,500
March 31, 2010			5,000
September 30, 2010			34,100
December 31, 2010			8,500
September 30, 2011			49,600
December 31, 2011			16,800
March 31, 2012			2,012
		$	182,512

These above monetized amounts were recorded in stockholders’ equity as part of other comprehensive income and are recognized in income over the contract life of the underlying hedge contracts. An additional $0.8 million monetization was captured in the September 30, 2011 quarter with the cash to be received when the underlying hedge contract settles during calendar 2013.

Our future crude oil and natural gas revenue will be increased by the following amounts related to the monetized contracts referred to above ( in thousands ):

Quarter Ended		Cash (1)				Non-Cash (1)				Total
June 30, 2012		$	11,023			$	—			$	11,023
September 30, 2012			9,537				—				9,537
December 31, 2012			9,046				—				9,046
March 31, 2013			4,821				204				5,025
Thereafter			14,628				621				15,249
		$	49,055			$	825			$	49,880

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 — Derivative Financial Instruments  – (continued)

As of March 31, 2012, we had the following contracts outstanding (Asset (Liability) and Fair Value (Gain) Loss in thousands ):

		Crude Oil																Natural Gas
										Total																Total								Total
Period		Volume (MBbls)				Contract Price (1)				Asset (Liability)				Fair Value Loss				Volume (MMBtu)				Contract Price (1)				Asset (Liability)				Fair Value (Gain)				Asset (Liability)				Fair (Gain) Loss (2)
WTI Commodity Collars
4/12 – 12/12			2,118			$	72.60/$100.19			$	(18,897	)		$	12,283																			$	(18,897	)		$	12,283
1/13 – 12/13			1,278				73.57/105.63				(9,281	)			6,033																				(9,281	)			6,033
											(28,178	)			18,316																				(28,178	)			18,316
Three-Way Collars
1/13 – 12/13			1,825				70/90/136.32				3,392				769																				3,392				769
1/14 – 12/14			3,650				70/90/137.14				9,079				197																				9,079				197
											12,471				966																				12,471				966
Swaps
4/12 – 12/12			138				86.60				(2,459	)			142																				(2,459	)			142
1/13 – 12/13			183				86.60				(3,065	)			188																				(3,065	)			188
4/12 – 12/12			(138	)			88.20				2,240																								2,240
1/13 – 12/13			(183	)			88.20				2,776																								2,776
											(508	)			330																				(508	)			330
Call Spread
1/13 – 12/13																			1,825			$	3.75/$4.75				410								410
Brent Commodity Collars
4/12 – 12/12			1,375				87.00/114.24				(14,816	)			9,630																				(14,816	)			9,630
1/13 – 12/13			3,103				80.00/126.78				(13,208	)			8,585																				(13,208	)			8,585
											(28,024	)			18,215																				(28,024	)			18,215
Three-Way Collars
4/12 – 12/12			3,355				66.93/86.93/133.55				(17,733	)			13,314				5,520				4.07/4.93/5.87				4,578				(2,976	)			(13,155	)			10,338
1/13 – 12/13			1,643				61.67/83.33/140.69				(1,833	)			2,615				10,950				4.07/4.93/5.87				7,088				(4,607	)			5,255				(1,992	)
1/14 – 12/14			1,278				66.43/86.43/141.36				572				1,389																				572				1,389
											(18,994	)			17,318												11,666				(7,583	)			(7,328	)			9,735
Total (Gain) Loss on Derivatives										$	(63,233	)		$	55,145											$	12,076			$	(7,583	)		$	(51,157	)		$	47,562

(1)

The contract price is weighted-averaged by contract volume.

(2)

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

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

		Asset Derivative Instruments																Liability Derivative Instruments
		As of March 31, 2012								As of June 30, 2011								As of March 31, 2012								As of June 30, 2011
		Balance Sheet Location				Fair Value				Balance Sheet Location				Fair Value				Balance Sheet Location				Fair Value				Balance Sheet Location				Fair Value
Commodity Derivative Instruments designated as hedging instruments:
Derivative financial instruments			Current			$	33,438				Current			$	6,048				Current			$	85,032				Current			$	58,593
			Non-Current				87,544				Non-Current				1,248				Non-Current				87,516				Non-Current				72,719
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments			Current				125				Current				2,310				Current				44				Current				3
			Non-Current				563				Non-Current				948				Non-Current				235				Non-Current
Total						$	121,670							$	10,554							$	172,827							$	131,315

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 — Derivative Financial Instruments  – (continued)

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

		Three Months Ended March 31,								Nine Months Ended March 31,
Location of (Gain) Loss in Income Statement		2012				2011				2012				2011
Cash Settlements, net of amortization of purchased put premiums:
Oil sales		$	3,009			$	16,370			$	2,576			$	28,537
Natural gas sales			(4,128	)			(9,732	)			(23,528	)			(27,569	)
Total cash settlements			(1,119	)			6,638				(20,952	)			968
Commodity Derivative Instruments designated as hedging instruments:
Loss (gain) on derivative financial instruments Ineffective portion of commodity derivative instruments			3,388				(157	)			1,713				58
Commodity Derivative Instruments not designated as hedging instruments:
Loss (gain) on derivative financial instruments Realized mark to market gain			23				—				(5,001	)			(3,226	)
Loss (gain) on derivative financial instruments Unrealized mark to market loss			84				(462	)			782				(227	)
Total loss (gain) on derivative financial instruments			3,495				(619	)			(2,506	)			(3,395	)
Total (gain) loss		$	2,376			$	6,019			$	(23,458	)		$	(2,427	)

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

		Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)								Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)								Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Location of (gain) loss		2012				2011				2012				2011				2012				2011
Three Months Ended March 31,
Commodity Derivative Instruments		$	39,757			$	104,180			$	—			$	—			$	—			$	—
Revenues			—				—				(1,349	)			(3,695	)			—				—
Loss (gain) on derivative financial instruments			—				—				—				—				3,388				(157	)
Total		$	39,757			$	104,180			$	(1,349	)		$	(3,695	)		$	3,388			$	(157	)
Nine Months Ended March 31,
Commodity Derivative Instruments		$	(52,837	)		$	172,302			$	—			$	—			$	—			$	—
Revenues			—				—				(16,658	)			(3,329	)			—				—
Loss on derivative financial instruments			—				—				—				—				1,713				58
Total		$	(52,837	)		$	172,302			$	(16,658	)		$	(3,329	)		$	1,713			$	58

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 — Derivative Financial Instruments  – (continued)

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 to 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, 2012, we had no deposits for collateral with our counterparties.

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

		Three Months Ended March 31,								Nine Months Ended March 31,
		2012				2011				2012				2011
Net income		$	91,252			$	18,371			$	254,672			$	29,438
Other comprehensive income (loss), net of tax:
Oil and gas cash flow hedges
Unrealized change in fair value including monetized hedges			(38,408	)			(100,485	)			69,495				(168,973	)
Reclassified to earnings during the period			(1,349	)			(3,695	)			(16,658	)			(3,329	)
Other comprehensive income (loss), net of tax:			(39,757	)			(104,180	)			52,837				(172,302	)
Comprehensive income (loss)		$	51,495			$	(85,809	)		$	307,509			$	(142,864	)

The amount expected to be reclassified to income in the next 12 months is a loss of $21.6 million ($14.0 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

Note 9 — 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 10.5%. The significant variance from the U.S. statutory rate is primarily due to the change in the valuation allowance (discussed below) against the U.S. net deferred tax assets and the accrual of the U.S. withholding obligation related to the interest income payable to the Bermuda Companies which may not be offset by other U.S. tax attributes. Our Bermuda Companies continue to report a tax provision reflecting accrued 30% U.S. withholding tax required on any interest payments made from the U.S. Companies to the Bermuda Companies. We have accrued a withholding obligation of $7.8 million for the nine months ended March 31, 2012.

During the year ended June 30, 2009, we incurred a significant impairment loss related to our oil and gas properties due to the steep decline in global energy prices over that same time period. As a result of this impairment, we were in a position of cumulative reporting losses for the preceding reporting periods. The volatility of energy prices since has been problematic and not readily determinable by our management. Under these circumstances, it has been management’s opinion that the realization of our tax attributes beyond expected current-year taxable income (including the reversal of existing taxable temporary differences and the resolution of certain hedging activity) does not reach the “more likely than not” criteria under ASC 740

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9 — Income Taxes  – (continued)

(formerly known as FAS 109). As a result, during the year ended June 30, 2009, we established a valuation allowance of $175.0 million, but have subsequently reduced the valuation allowance due to the presence of actual earnings reported in quarters since establishment of the allowance. If current indications of pre-tax earnings for the year prove to be correct, we will release approximately $90 million of our remaining valuation allowance during this fiscal year (which has been reflected in the estimated annual effective tax rate indicated above). While the Company has not made significant income tax payments in recent years, in light of expected income in this fiscal year and subsequent years, estimated tax payments in subsequent quarters (possibly as early as the second quarter of fiscal year 2013) may be required in amounts yet to be determined in accordance with the applicable federal income tax provisions related to required corporate estimated tax payments.

Note 10 — 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.

Preferred Stock

Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. The number of authorized preferred shares we are authorized to issue was increased to 7,500,000 shares from 2,500,000 shares, and approved by shareholders at the Annual General Meeting held in November 2011. 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 March 15, June 15, September 15 and December 15 of each year.

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 February and March 2012, we cancelled and converted a total of 235,780 shares of our 5.625% Preferred Stock into a total of 2,318,961 shares of Common Stock. In addition to the stated conversion rate of 9.8353 common shares per preferred share, we paid cash of $6.1 million, of which $0.7 million was paid towards accrued dividends and the remaining $5.4 million was paid to induce the conversion.

At March 31, 2012, we have 814,220 shares of 5.625% Preferred Stock and 8,000 shares of 7.25% Preferred Stock issued and outstanding.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11 — 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,
		2012				2011				2012				2011
Cash paid for interest		$	4,698			$	7,662			$	56,721			$	49,938

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

		Three Months Ended March 31,								Nine Months Ended March 31,
		2012				2011				2012				2011
Financing of insurance premiums		$	(8,558	)		$	(6,574	)		$	(19,215	)		$	—
Conversion of preferred stock to common stock			—				—				—				(7,884	)
Preferred stock dividends			(138	)			(1,874	)			(138	)			371
Additions to property and equipment by recognizing asset retirement obligations			700				6,483				2,037				213,650

Note 12 — 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 (or “Phantom Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. The Phantom Stock Units generally vest equally over a three-year period. When vesting occurs, we pay the employee an amount equal to the then current common share price times the number of Phantom Stock Units that have vested, plus the cumulative value of dividends applicable to our common stock.

For fiscal 2010 and 2011, we also awarded 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 Phantom Stock Units and Performance Based 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 Phantom Stock Units and Performance Based Units become immediately vested and payable. Historically, we have paid all vesting awards in cash. The July 21, 2011 vesting of the July 21, 2010 and 2009 Performance Based Unit awards were paid 50% in common stock and future vesting of the Performance Based Units may be paid in stock at the discretion of our board of directors.

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

		Three Months Ended March 31,								Nine Months Ended March 31,
		2012				2011				2012				2011
Phantom Stock Units		$	6,897			$	6,850			$	17,032			$	15,516
Performance Units			10,055				8,590				27,007				22,469
Total compensation expense recognized		$	16,952			$	15,440			$	44,039			$	37,985

As of March 31, 2012, we have 914,707 unvested Phantom Stock Units and 3,891,438 unvested Performance Based Units.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans  – (continued)

Restricted Shares

Restricted Shares activity is as follows:

		Number Of Shares				Grant-date Fair value Per Share
Non-vested at June 30, 2011			31,214			$	24.75
Vested during the nine months ended March 31, 2012			(31,214	)
Non-vested at March 31, 2012			—

We determine the fair value of the Restricted Shares based on the market price of our Common Stock on the date of grant. Compensation cost for the Restricted Shares is recognized on a straight line basis over the requisite service period. For the three months and nine months ended March 31, 2012, we recognized compensation expense of none and $49,000 and for the three months and nine months ended March 31, 2011 we recognized compensation expense of $200,000 and $800,000, related to our Restricted Shares.

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, 2012 and 2011, we issued 277,980 shares and 281,354 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 period. The current period is from January 1, 2012 to June 30, 2012.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,
		2012				2011				2012				2011
Compensation expense		$	215			$	189			$	516			$	378
Shares issued			—				—				21,015				89,260

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, 2012, 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

Note 12 — Employee Benefit Plans  – (continued)

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

		Nine Months Ended March 31,
		2012								2011
		Unvested Shares Under Option				Weighted Ave. Exercise Price				Unvested Shares Under Option				Weighted Ave. Exercise Price
Beginning balance –  unvested options			100,000			$	17.50				240,000			$	17.50
Vested			(100,000	)			17.50				(140,000	)			17.50
Ending balance –  unvested options			—			$	17.50				100,000			$	17.50

Our net income for the three and nine months ended March 31, 2012 includes expense of approximately none and $58,000 and for the three months and nine months ended March 31, 2011 includes expense of approximately $88,000 and $129,000 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 for the three months and nine months ended March 31, 2012 and 2011 were as follows ( in thousands ):

		Three Months Ended March 31,								Nine Months Ended March 31,
		2012				2011				2012				2011
Profit Sharing Plan		$	(49	)		$	724			$	1,756			$	1,941
401(k) Plan			1,360				391				2,866				1,489
Total contributions		$	1,311			$	1,115			$	4,622			$	3,430

Note 13 — Earnings per Share

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

		Three Months Ended March 31,								Nine Months Ended March 31,
		2012				2011				2012				2011
Net income		$	91,252			$	18,371			$	254,672			$	29,438
Preferred stock dividends			2,739				4,278				10,151				8,698
Induced Conversion of Preferred Stock			6,058				44				6,058				19,840
Net income available for common stockholders		$	82,455			$	14,049			$	238,463			$	900

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13 — Earnings per Share  – (continued)

		Three Months Ended March 31,								Nine Months Ended March 31,
		2012				2011				2012				2011
Weighted average shares outstanding for basic EPS			77,454				74,221				76,803				63,490
Add dilutive securities			9,899				200				10,382				242
Weighted average shares outstanding for diluted EPS			87,353				74,421				87,185				63,732
Net income per share attributable to common stockholders
Basic		$	1.06			$	0.19			$	3.10			$	0.01
Diluted		$	1.04			$	0.19			$	2.92			$	0.01

For the three months and nine months ended March 31, 2012, 1,314 and 3,056 common stock equivalents, respectively, were excluded from the diluted average shares due to an anti-dilutive effect. For the three months and nine months ended March 31, 2011, 12,178,031 and 11,227,616 common stock equivalents, respectively, were excluded from the diluted average shares due to an anti-dilutive effect.

Note 14 — Commitments and Contingencies

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

Lease Commitments.   We have non-cancelable operating leases for office space and other that expire through December 31, 2018. Future minimum lease commitments as of March 31, 2012 under the operating lease are as follows (in thousands ):

Twelve Months Ending March 31,
2013		$	2,185
2014			2,100
2015			1,735
2016			1,798
2017			1,840
Thereafter			1,897
Total		$	11,555

Rent expense, including rent incurred on short-term leases, for the three months and nine months ended March 31, 2012 was approximately $943,000 and $1,839,000 and for the three months and nine months ended March 31, 2011 was approximately $512,000 and $1,457,000.

Letters of Credit and Performance Bonds.   We had $231.5 million in letters of credit and $25.1 million in performance bonds outstanding as of March 31, 2012.

Line of Credit.   Our equity method investee, Energy XXI Natural Gas Partners, LLC, of which we own 20%, is a guarantor of a $100 million line of credit entered into by its wholly owned subsidiary, Natural Gas Partners Assets, LLC on February 23, 2012. As of March 31, 2012, the borrowing base under this facility was $0.

Drilling Rig Commitments.   As of March 31, 2012, we have entered into five drilling rig commitments, the first of which commenced on July 3, 2011 at $42,500 per day for one well until well completion. The second commitment commenced on October 1, 2011 at $65,000 per day for six months and was extended for

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14 — Commitments and Contingencies  – (continued)

nine months at $75,000 per day. The third commenced on November 4, 2011 at $47,800 per day for four wells until well completion with options to do additional work. The fourth commenced on March 5, 2012 at $125,000 per day to drill two wells and three recompletions. The last one commenced on March 10, 2012 at $65,000 per day for two wells until well completion. Since the preceding commitments are not finished and extend past March 31, 2012, the commitment amounts cannot be calculated since the well completion dates are not known.

Note 15 — 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 8 — Derivative Financial Instruments.

The fair value of our stock based units are based on period-end stock price for our Phantom Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model is used for performance-based units.

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 (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:

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 — Fair Value of Financial Instruments  – (continued)

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

		Level 1								Level 2								Level 3
		As of March 31, 2012				As of June 30, 2011				As of March 31, 2012				As of June 30, 2011				As of March 31, 2012				As of June 30, 2011
Assets:
Oil and Natural Gas Derivatives		$	—			$	—			$	121,670			$	10,554			$	—			$	—
Liabilities:
Oil and Natural Gas Derivatives		$	—			$	—			$	172,827			$	131,315				—				—
Phantom Stock Units			13,144				17,866				—				—				—				—
Performance Units			3,667				3,611				—				—				19,818				20,306
Total		$	16,811			$	21,477			$	172,827			$	131,315			$	19,818			$	20,306

Note 16 — Prepayments and Accrued Liabilities

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

		March 31, 2012				June 30, 2011
Prepaid expenses and other current assets
Advances to joint interest partners		$	21,202			$	14,696
Insurance			5,291				23,230
Inventory			5,404				6,305
Royalty deposit			2,443				1,959
Short-term stock investment			6,189				—
Other			2,226				1,561
Total prepaid expenses and other current assets		$	42,755			$	47,751
Accrued liabilities
Advances from joint interest partners		$	552			$	437
Employee benefits and payroll			35,391				53,789
Interest			25,887				5,806
Accrued hedge payable			5,341				14,095
Undistributed oil and gas proceeds			30,815				31,880
Other			4,856				5,150
Total accrued liabilities		$	102,842			$	111,157

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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 volatility through December 2013 by implementing a hedging program on a portion of our total anticipated production during this time frame. See Note 8 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 as is currently being experienced in the natural gas market. 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. We do not anticipate an out-of-cycle borrowing base redetermination as a result of low natural gas prices and expect our next redetermination to occur as scheduled in the spring of 2012.

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. Increased regulation in a number of areas could disrupt, delay or prohibit future drilling programs and ultimately impact the fair value of our unevaluated properties. As of March 31, 2012, we have approximately $225 million of investments in unevaluated oil and gas properties related to ultra-deep shelf exploration. If the fair value of these investments were to fall below the recorded amounts, the excess would be transferred to evaluated oil and gas properties thereby affecting the computation of amounts for depreciation, depletion and amortization and potentially our ceiling test computation. As of March 31, 2012, the computation of our ceiling test indicated a cushion of approximately $1.9 billion.

Operational Highlights

Ultra-Deep Shelf/Onshore Exploration and Development Activity

We participate in a joint venture (the “Partnership”) led by McMoRan Exploration Company with respect to several prospects in the ultra-deep shelf 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, the Partnership has identified approximately 15 ultra-deep shelf prospects in shallow water near existing infrastructure. The Partnership’s ultra-deep shelf drilling plans in calendar years 2010 thru 2012 included the Blackbeard East, Lafitte and Lineham Creek exploratory wells and delineation drilling at Davy Jones. The Partnership’s near-term sub-salt shelf drilling plans include two to three exploratory wells. We expect to have sufficient cash flow from operations to fund our current commitments related to our ultra-deep shelf exploration and development activity.

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As previously reported, the Partnership has 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 Partnership expects to commence the completion of the Davy Jones No. 2 well in the second half of 2012. The Davy Jones field involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). As of March 31, 2012, our investment in both wells in the Davy Jones field totaled about $96 million.

Davy Jones.   The Davy Jones No. 1 well on South Marsh Island Block 230 was successfully completed in March 2012 and work is ongoing to establish commercial production from the well. 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. Blockage from drilling fluid associated with initial drilling operations prevented the Partnership from obtaining a measurable flow rate. Attempts to perforate the Wilcox “C” sand did not clear the blockage. In April 2012, the Partnership commenced operations to remove the tubing from the well, clear the residual drilling fluid, and remove the perforating guns currently set across the Wilcox “F” sand to provide access to all of the Wilcox reservoirs (“A” through “F”) totaling 200 net feet. To maximize production from the well and enable effective formation penetrations, the Partnership plans to use electric wireline casing guns that are larger than the tubing guns used to perforate the Wilcox “C” and “D” sands. We expect the operations currently underway will enable a measurable flow rate during the fourth quarter of Fiscal 2012 followed by commercial production shortly thereafter.

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 GOM Shelf or in the deepwater offshore Louisiana. The Partnership is evaluating development options associated with these formations. 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. Blackbeard East is located in 80 feet of water on South Timbalier Block 144. As of March 31, 2012, our investment in the well totaled about $49 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 GOM Shelf or in the deepwater offshore Louisiana. The Partnership is evaluating development options associated with these formations. As of March 31, 2012, our investment in the well totaled about $38 million.

Blackbeard West.   Information gained from the Blackbeard East and Lafitte wells will enable the Partnership 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 is drilling below 20,000 feet. The well, which is located on Ship Shoal Block 188 within the Blackbeard West unit, is targeting Miocene aged sands seen below the salt weld approximately 13 miles east at Blackbeard East and has a proposed total depth of 26,000 feet. Our investment in both Blackbeard West wells totaled about $37 million at March 31, 2012.

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 December 31, 2011. The well, which is

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targeting Eocene and Paleocene objectives below the salt weld, has been drilled to 14,876 feet towards a proposed total depth of 29,000 feet. As of March 31, 2012, our investment in the Lineham Creek well totaled about $5 million.

Known Trends and Uncertainties

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 Bureau of Safety and Environmental Enforcement (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 Gulf of Mexico (“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

Ultra-Deep Shelf Exploration and Development.   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, the Partnership has identified approximately 15 additional ultra-deep shelf prospects in shallow water near existing infrastructure. We expect to have sufficient cash flow from operations to fund our current commitments related to our ultra-deep shelf exploration and development activity in 2012. We have participated in seven wells to date with our interest ranging from approximately 9% to 20% per well. Of these wells, one is pending further evaluation and six are in process. We target to spend less than 15% of our cash flow on our exploration activities on the ultra-deep shelf. Of the seven wells with activity to date one has been temporarily abandoned pending further evaluation, one is completing, one is temporarily abandoned pending facilities and completions later this fiscal year, two are being evaluated for development options and two are currently drilling. Based on the results of these wells, our proved reserves may vary from our June 30, 2011 66% oil composition.

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Operational Information ( In thousands except for unit amounts )

		Quarter Ended
Operating Highlights		Mar. 31, 2012				Dec. 31, 2011				Sept. 30, 2011				June 30, 2011				Mar. 31, 2011
Operating revenues
Crude oil sales		$	315,723			$	306,064			$	249,767			$	270,252			$	233,081
Natural gas sales			19,154				21,659				28,138				31,875				32,193
Hedge gain (loss)			1,119				12,855				6,978				(19,346	)			(6,638	)
Total revenues			335,996				340,578				284,883				282,781				258,636
Percent of operating revenues from crude oil
Prior to hedge gain (loss)			94	%			93	%			90	%			89	%			88	%
Including hedge gain (loss)			93	%			91	%			87	%			85	%			84	%
Operating expenses
Lease operating expense
Insurance expense			7,138				7,096				7,462				8,814				6,543
Workover and maintenance			15,885				12,805				6,653				17,251				4,121
Direct lease operating expense			55,424				54,233				56,918				59,557				54,593
Total lease operating expense			78,447				74,134				71,033				85,622				65,257
Production taxes			1,499				1,174				2,174				1,205				721
Gathering and transportation			2,465				3,395				6,153				6,868				4,809
DD&A			88,448				87,568				84,803				85,179				91,301
General and administrative			25,075				22,147				19,321				17,553				23,155
Other – net			13,257				14,174				(684	)			7,730				9,288
Total operating expenses			209,191				202,592				182,800				204,157				194,531
Operating income		$	126,805			$	137,986			$	102,083			$	78,624			$	64,105
Sales volumes per day
Natural gas (MMcf)			83.7				72.8				77.0				83.0				84.6
Crude oil (MBbls)			31.4				30.6				28.0				28.3				27.3
Total (MBOE)			45.3				42.7				40.8				42.1				41.4
Percent of sales volumes from crude oil			69	%			72	%