- Quarterly Report (10-Q)

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

	FORM 10-Q

	(Mark One)
	[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
	SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2011
	OR
	[ ]	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: 001-07791



	McMoRan Exploration Co.
	(Exact name of registrant as specified in its charter)

Delaware			72-1424200
(State or other jurisdiction of incorporation or organization)			(IRS Employer Identification No.)

1615 Poydras Street
New Orleans, Louisiana			70112
(Address of principal executive offices)			(Zip Code)

(504) 582-4000
(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. S Yes o No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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). S Yes o No 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 definition of “large accelerated filer,” “ accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:
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. o Yes S No On July 29, 2011, there were issued and outstanding 158,486,564 shares of the registrant’s Common Stock, par value $0.01 per share.


McMoRan Exploration Co.
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	Page

Part I. Financial Information

Item 1. Financial Statements :

Condensed Consolidated Balance Sheets (Unaudited)	3

Consolidated Statements of Operations (Unaudited)	4

Consolidated Statements of Cash Flow (Unaudited)	5

Consolidated Statement of Equity (Unaudited)	6

Notes to Consolidated Financial Statements (Unaudited)	7

Report of Independent Registered Public Accounting Firm	24

Item 2. Management's Discussion and Analysis
of Financial Condition and Results of Operations	25

Item 3. Quantitative and Qualitative Disclosures about Market Risks	37

Item 4. Controls and Procedures	38

Part II. Other Information

Item 1. Legal Proceedings	38

Item 1A. Risk Factors	38

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 6. Exhibits	39

Signature	40

Exhibit Index	E-1

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Part I. FINANCIAL INFORMATION

Item 1. Financial Statements .

McMoRan EXPLORATION CO.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited )

	June 30,		December 31,
	2011		2010
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	765,320	$	905,684
Accounts receivable		100,317		86,516
Inventories		32,023		38,461
Prepaid expenses		5,793		15,478
Current assets from discontinued operations, including restricted cash
of $473		1,367		702
Total current assets		904,820		1,046,841
Property, plant and equipment, net		1,915,443		1,785,607
Restricted cash		56,483		53,975
Deferred financing costs and other assets		9,399		9,952
Long-term assets from discontinued operations		2,989		2,989
Total assets	$	2,889,134	$	2,899,364

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	108,035	$	102,658
Accrued liabilities		162,753		99,363
Accrued interest and dividends payable		14,798		6,768
Current portion of accrued oil and gas reclamation costs		153,636		120,970
5¼% convertible senior notes		74,720		74,720
Current portion of accrued sulphur reclamation costs (discontinued operations)		8,681		11,772
Current liabilities from discontinued operations		1,652		1,993
Total current liabilities		524,275		418,244
11.875% senior notes		300,000		300,000
4% convertible senior notes		186,309		185,256
Accrued oil and gas reclamation costs		183,736		237,654
Other long-term liabilities		15,963		16,596
Accrued sulphur reclamation costs (discontinued operations)		14,020		13,494
Other long-term liabilities from discontinued operations		4,301		3,783
Total liabilities		1,228,604		1,175,027
Stockholders' equity		1,660,530		1,724,337
Total liabilities and stockholders' equity	$	2,889,134	$	2,899,364

The accompanying notes are an integral part of these condensed consolidated financial statements.

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited )

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(In Thousands, Except Per Share Amounts)
Revenues:
Oil and natural gas	$	155,469		$	104,103		$	289,181		$	232,949
Service		2,839			3,938			6,131			7,580
Total revenues		158,308			108,041			295,312			240,529
Costs and expenses:
Production and delivery costs		51,911			46,439			99,868			89,224
Depletion, depreciation and amortization expense		95,338			57,887			182,008			166,132
Exploration expenses		47,896			10,434			60,674			22,843
(Gain) loss on oil and gas derivative contracts		-			477			-			(3,268	)
General and administrative expenses		11,223			10,376			27,175			24,119
Main Pass Energy Hub ™ costs		278			242			513			575
Insurance recoveries		(12,946	)		(9,171	)		(29,369	)		(9,171	)
Gain on sale of oil and gas property		-			(3,455	)		(900	)		(3,455	)
Total costs and expenses		193,700			113,229			339,969			286,999
Operating loss		(35,392	)		(5,188	)		(44,657	)		(46,470	)
Interest expense, net		(2,704	)		(9,873	)		(8,153	)		(20,406	)
Other income, net		230			44			410			105
Loss from continuing operations before income taxes		(37,866	)		(15,017	)		(52,400	)		(66,771	)
Income tax expense		-			-			-			-
Loss from continuing operations		(37,866	)		(15,017	)		(52,400	)		(66,771	)
Loss from discontinued operations		(1,989	)		(1,436	)		(3,233	)		(3,076	)
Net loss		(39,855	)		(16,453	)		(55,633	)		(69,847	)
Preferred dividends and inducement payments for early
conversion of convertible preferred stock		(10,343	)		(5,293	)		(22,115	)		(18,059	)
Net loss applicable to common stock	$	(50,198	)	$	(21,746	)	$	(77,748	)	$	(87,906	)

Basic and diluted net loss per share of common
stock:
Continuing operations		$(0.31	)		$(0.22	)		$(0.47	)		$(0.93	)
Discontinued operations		(0.01	)		(0.01	)		(0.02	)		(0.03	)
Net loss per share of common stock		$(0.32	)		$(0.23	)		$(0.49	)		$(0.96	)

Average common shares outstanding:
Basic and diluted		158,454			93,101			158,154			91,428

The accompanying notes are an integral part of these consolidated financial statements.

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW (Unaudited )

	Six Months Ended
	June 30,
	2011			2010
	(In Thousands)
Cash flow from operating activities:
Net loss	$	(55,633	)	$	(69,847	)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Loss from discontinued operations		3,233			3,076
Depletion, depreciation and amortization expense		182,008			166,132
Exploration drilling and related expenditures, net		38,886			7,471
Compensation expense associated with stock-based awards		12,814			12,657
Amortization of deferred financing costs		3,030			1,862
Change in fair value of oil and gas derivative contracts		-			4,110
Reclamation expenditures, net of prepayments by third parties		(42,235	)		(41,632	)
Increase in restricted cash		(2,508	)		(7,506	)
Gain on sale of oil and gas property		(900	)		(3,455	)
Other		(313	)		556
(Increase) decrease in working capital:
Accounts receivable		(42,594	)		(7,588	)
Accounts payable and accrued liabilities		30,600			11,086
Prepaid expenses and inventories		17,675			16,775
Net cash provided by continuing operations		144,063			93,697
Net cash used in discontinued operations		(7,923	)		(2,164	)
Net cash provided by operating activities		136,140			91,533

Cash flow from investing activities:
Exploration, development and other capital expenditures		(258,894	)		(101,436	)
Proceeds from sale of oil and gas property		900			2,920
Net cash used in continuing operations		(257,994	)		(98,516	)
Net cash from discontinued operations		-			-
Net cash used in investing activities		(257,994	)		(98,516	)

Cash flow from financing activities :
Dividends paid and inducement payments on early conversion of
convertible preferred stock		(17,267	)		(17,589	)
Credit facility refinancing fees		(1,609	)		-
Debt and equity issuance costs		(543	)		-
Proceeds from exercise of stock options and other		909			182
Net cash used in continuing operations		(18,510	)		(17,407	)
Net cash from discontinued operations		-			-
Net cash used in financing activities		(18,510	)		(17,407	)
Net decrease in cash and cash equivalents		(140,364	)		(24,390	)
Cash and cash equivalents at beginning of year		905,684			241,418
Cash and cash equivalents at end of period	$	765,320		$	217,028

The accompanying notes are an integral part of these consolidated financial statements.

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENT OF EQUITY (Unaudited )

Six Months Ended June 30, 2011

	Preferred stock			Common stock		Capital in excess of par value			Accumulated deficit			Accumulated other comprehensive loss			Common stock held in treasury			Total Stockholders’ Equity
Balance as of December 31, 2010	$	722,063		$	1,598	$	2,156,430		$	(1,107,481	)	$	(97	)	$	(48,176	)	$	1,724,337
Stock-based compensation
expense		-			-		12,814			-			-			-			12,814
Preferred stock dividends and
conversion inducement payments		-			-		(22,115	)		-			-			-			(22,115	)
Preferred stock conversions		(8,064	)		11		8,053			-			-			-			-
Preferred stock offering cost adjustments		-			-		275			-			-			-			275
Stock option exercises and other		-			1		911			-			-			(40	)		872
Net loss		-			-		-			(55,633	)		-			-			(55,633	)
Other comprehensive loss		-			-		-			-			(20	)		-			(20	)
Balance as of June 30, 2011	$	713,999		$	1,610	$	2,156,368		$	(1,163,114	)	$	(117	)	$	(48,216	)	$	1,660,530

The accompanying notes are an integral part of this consolidated financial statement.

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McMoRan EXPLORATION CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. BASIS OF PRESENTATION

The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware corporation, are prepared in accordance with U.S. generally accepted accounting principles. McMoRan’s consolidated financial statements include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and where the right to participate in significant management decisions is not shared with other shareholders, including its two wholly owned subsidiaries, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy). MOXY conducts all of McMoRan’s oil and gas operations. The long-term business objective of Freeport Energy is to maximize the value of the offshore structures used in the former sulphur operations, which may include the pursuit of a multifaceted energy services facility at the Main Pass Energy Hub (MPEH ™ ) project located at Main Pass Block 299 (Main Pass). McMoRan’s previously discontinued sulphur operations are presented as discontinued operations, and the major classes of assets and liabilities related to its former sulphur business are separately shown for the periods presented.

The accompanying unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in McMoRan’s Annual Report on Form 10-K for the year ended December 31, 2010 (2010 Form 10-K). The information furnished herein reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the results for the periods presented. All such adjustments are, in the opinion of management, of a normal recurring nature.

2. ACQUISITION OF GULF OF MEXICO SHELF PROPERTIES

On December 30, 2010, McMoRan completed the $1 billion acquisition of Plains Exploration & Production Company’s (PXP) shallow water Gulf of Mexico shelf assets (PXP Acquisition). Under the terms of the transaction, McMoRan issued 51 million shares of its common stock and paid $75.0 million in cash to PXP. In addition, the purchase price included additional consideration associated with estimated revenues, expenses and capital expenditures attributable to the acquired properties from the August 1, 2010 effective date through the December 30, 2010 closing date, and the assumption of related asset retirement obligations. The substantial majority of properties acquired from PXP represented their interests in certain deep gas and ultra-deep exploration projects that were jointly owned by McMoRan and PXP prior to the transaction. Concurrent with the PXP Acquisition, McMoRan issued $700 million of 5.75% Convertible Perpetual Preferred Stock (5.75% preferred stock) and $200 million of 4% Convertible Senior Notes (4% notes). See notes 2, 6 and 8 of the 2010 Form 10-K for additional information regarding the PXP Acquisition and related financing transactions.

The following unaudited pro forma financial information for the three and six-month periods ended June 30, 2010 includes adjustments to McMoRan’s historical financial data to reflect the pro forma impact of the PXP Acquisition and related financing transactions (in thousands, except per share data):

	Second Quarter			Six Months
	2010			2010
Revenues	$	135,940		$	309,941
Operating income (loss)		3,916			(40,531	)
Net loss to common shareholders		(25,293	)		(107,270	)
Basic and diluted net loss per share of common stock	$	(0.18	)	$	(0.75	)

The pro forma operating loss and net loss amounts reflected above include pro forma adjustments for certain exploration and asset impairment charges that McMoRan would have recorded under the successful efforts method of accounting assuming the impact of the PXP Acquisition had been included in McMoRan’s historical results of operations. Those amounts include $4.0 million and $9.7 million of non-productive exploratory drilling costs for the three and six month periods ended June 30, 2010, respectively and $18.6 million of asset impairment charges for only the six month period ended June 30, 2010.

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3. LONG-TERM DEBT

McMoRan’s long-term debt is summarized below (in thousands).

	June 30,			December 31,
	2011			2010
Senior secured revolving credit facility	$	-		$	-
11.875% senior notes		300,000			300,000
5¼% convertible senior notes		74,720			74,720
4% convertible senior notes, net of discount of $13,691 and $14,744		186,309			185,256
Total debt		561,029			559,976
Less current maturities		(74,720	)		(74,720	)
Long-term debt	$	486,309		$	485,256

Senior Secured Revolving Credit Facility

During the second quarter of 2011 McMoRan entered into a new variable rate senior secured revolving credit facility (credit facility). The new credit facility is secured by substantially all of MOXY’s oil and gas properties and matures on June 30, 2016, provided that by August 16, 2014 McMoRan’s 11.875% senior notes will have been redeemed or refinanced with senior notes with a term extending at least through 2016; otherwise the maturity date will be August 16, 2014. The facility’s borrowing capacity is $150 million, and under certain conditions it may be increased to a capacity of $300 million with additional lender commitments. The terms of the new facility are substantially the same as McMoRan’s prior revolving credit agreement. There were no borrowings outstanding under the revolving credit agreement during the quarter ended June 30, 2011. After giving effect to a $100 million letter of credit outstanding as surety support to a third party associated with reclamation obligations, availability totaled $50 million.

Availability under the credit facility is subject to a borrowing base, which is redetermined semi-annually each April and October.

The credit facility includes covenants and other restrictions customary for oil and gas borrowing base credit facilities. McMoRan was in compliance with these covenants at June 30, 2011.

Fair Value of Debt

The fair value of McMoRan’s 5¼% convertible senior notes due October 2011 (5¼% notes), 11.875% senior notes due November 2014 (11.875% senior notes) and 4% notes is determined at the end of each reporting period using inputs based upon quoted prices for such instruments in active markets. The following table reflects the estimated fair value of these obligations as of June 30, 2011 and December 31, 2010 (in thousands):

	June 30,		December 31,
	2011		2010
5¼% convertible senior notes	$	84,927	$	89,335
11.875% senior notes		324,750		331,500
4% convertible senior notes		267,874		255,000

Interest Expense, Net

Interest expense, which includes the amortization of deferred financing costs and periodic revolving credit facility fees, is reflected net of amounts capitalized to McMoRan’s in-progress drilling projects. Interest expense capitalized by McMoRan totaled $11.6 million in the second quarter of 2011 and $20.5 million for the six months ended June 30, 2011. Capitalized interest totaled $1.9 million in the second quarter of 2010 and $3.1 million for the six months ended June 30, 2010.

4. EARNINGS PER SHARE

Basic net loss per share of common stock has been calculated by dividing the net loss applicable to continuing operations, net loss from discontinued operations and net loss applicable to common stock by the weighted-average number of common shares outstanding during the periods presented. For purposes of the earnings per share computations, the net loss applicable to continuing operations includes preferred stock dividends and inducement payments.

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McMoRan had a net loss from continuing operations in both the second quarter and six months ended June 30, 2011 and 2010. Accordingly, the incremental common shares that would have been issued upon exercise of stock options, as well as conversion of McMoRan’s 5.75% preferred stock, 8% convertible perpetual preferred stock (8% preferred stock), 6¾% mandatorily convertible preferred stock (6¾% preferred stock), 4% notes and 5¼% notes have been excluded from the diluted net loss per share calculations. These common shares were excluded because their issuance is considered to be anti-dilutive, as their inclusion would have reduced the reported net loss per share from continuing operations during these periods. The excluded common share amounts are summarized below (in thousands):

	Second Quarter				Six Months
	2011		2010		2011		2010
Stock options a		1,982		1,057		2,263		1,162
Shares issuable upon assumed
conversion of:
5.75% preferred stock b		43,750		-		43,750		-
8% preferred stock b		2,046		1,722		2,306		6,033
6¾% preferred stock b		-		12,817		-		12,817
5¼% notes c		4,508		4,508		4,508		4,508
4% notes c		12,500		-		12,500		-

McMoRan uses the treasury stock method to determine total shares related to in-the-money stock options for purposes of its diluted earnings per share calculation. The amounts represent stock options with an exercise price that is less than the average market price for McMoRan’s common stock for the periods presented.

Amount represents total equivalent common shares assuming conversion of the preferred stock. During the first quarter of 2011, McMoRan induced conversion of approximately 8,100 shares, of its 8% preferred stock and during the second quarter and six months ended 2010, McMoRan induced conversion of approximately 9,600 shares and 57,200 shares of its 8% preferred stock, respectively (Note 9). Preferred dividends and inducement payments for the early conversion of shares of McMoRan’s 8% preferred stock totaled $10.3 million and $22.1 million for the three and six month periods ended June 30, 2011, respectively and $5.3 million and $18.1 million for the three and six month periods ended June 30, 2010, respectively. See Note 8 of the 2010 Form 10-K for additional information regarding McMoRan’s 5.75% preferred stock, 8% preferred stock and 6¾% preferred stock.

Interest expense, net on the 5¼% notes totaled $0.2 million and $0.9 million during the second quarters of 2011 and 2010, respectively and $0.6 million and $1.9 million for the six months ended June 30, 2011 and 2010. Interest expense, net on the 4% notes totaled $0.5 million and $1.5 million, respectively, during the second quarter and six months ended June 30, 2011. Additional information regarding McMoRan’s 4% notes and 5¼% notes is disclosed in Note 6 of the 2010 Form 10-K.

Outstanding stock options which were excluded from the computation of diluted net loss per share of common stock because their exercise prices were higher than the average market price of McMoRan’s common stock during the periods presented follow:

	Second Quarter				Six Months
	2011		2010		2011		2010
Outstanding options (in thousands)		1,346		9,124		1,356		7,849
Average exercise price	$	20.19	$	15.92	$	20.17	$	16.51

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5. STOCK-BASED COMPENSATION

Compensation cost charged to expense for stock-based awards follows (in thousands):

	Second Quarter				Six Months
	2011		2010		2011		2010
Stock options awarded to employees (including directors)	$	2,731	$	2,681	$	12,115	$	11,947
Stock options awarded to non-employees		133		178		506		510
Restricted stock units		102		110		193		200
Total stock-based compensation cost	$	2,966	$	2,969	$	12,814	$	12,657

A summary of the classification of stock-based compensation by financial statement line item for the second quarter and six month periods ended June 30, 2011 and 2010 follows (in thousands):

	Second Quarter				Six Months
	2011		2010		2011		2010

General and administrative expenses	$	1,639	$	1,594	$	6,872	$	6,524
Exploration expenses		1,305		1,324		5,837		5,919
Main Pass Energy Hub costs		22		51		105		214
Total stock-based compensation cost	$	2,966	$	2,969	$	12,814	$	12,657

On February 7, 2011, McMoRan’s Board of Directors granted 1,737,500 stock options to its employees at an exercise price of $17.25 per share, including immediately exercisable options for an aggregate of 445,000 shares. Options representing 400,000 of these 445,000 shares were issued to McMoRan’s Co-Chairmen in lieu of cash compensation in 2011. McMoRan recorded $7.2 million in charges related to immediately vested stock options in the first quarter of 2011. These charges included the compensation costs associated with the immediately exercisable options and the compensation costs related to stock options granted to retiree-eligible employees, which resulted in one-year’s compensation expense being immediately recognized at the effective date of the stock option grant. The weighted average per share value of the 1,857,500 options granted during the six months ended June 30, 2011 was $10.76. McMoRan’s Board of Directors granted 1,766,500 stock options to its employees at an exercise price of $15.73 per share on February 1, 2010. The weighted average per share value of the 1,816,500 options granted during the six months ended June 30, 2010 was $10.18. McMoRan recorded $6.7 million in charges related to immediately vested stock options in the first quarter of 2010.

As of June 30, 2011, total compensation cost related to nonvested approved stock option awards not yet recognized in earnings was approximately $20.3 million, which is expected to be recognized over a weighted average period of approximately one year.

For additional information regarding McMoRan’s accounting for stock-based awards, see Notes 1 and 11 of the 2010 Form 10-K.

6. DERIVATIVE CONTRACTS

In connection with a 2007 oil and gas property acquisition and related financing, MOXY entered into derivative contracts for a portion of the anticipated production from its proved developed producing oil and gas properties at the time of the acquisition for the years 2008 through 2010. See Note 1 of the 2010 Form 10-K for McMoRan’s accounting policies regarding these derivative contracts.

Because these oil and gas derivative contracts were not designated as hedges for accounting purposes, unrealized (gains) losses representing changes in the related fair values along with realized (gains) losses representing cash settlements are recognized immediately in McMoRan’s operating results at each reporting period. McMoRan’s realized and unrealized (gains) losses on these contracts were as follows (in thousands):

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	Second Quarter			Six Months
	2010			2010
Realized (gain) loss
Gas puts	$	-		$	-
Oil puts		-			-
Gas swaps		(4,402	)		(8,134	)
Oil swaps		327			756
Total realized gain		(4,075	)		(7,378	)

Unrealized (gain) loss
Gas puts		616			(467	)
Oil puts		-			42
Gas swaps		4,675			5,643
Oil swaps		(739	)		(1,108	)
Total unrealized loss		4,552			4,110
(Gain) loss on oil and gas derivative contracts	$	477		$	(3,268	)

All remaining derivative contract positions matured on December 31, 2010.

7. INCOME TAXES

As of June 30, 2011 and December 31, 2010, McMoRan had approximately $472.4 million and $452.9 million, respectively, of unrecognized tax benefits relating to its reported net losses and other temporary differences from operations. McMoRan recorded a full valuation allowance against these deferred tax assets (see Note 12 of the 2010 Form 10-K). If future circumstances permit the allowance to be reversed, McMoRan’s effective tax rate would be positively affected in future periods to the extent these deferred tax assets are recognized.

Interest or penalties associated with income taxes are recorded as components of the provision for income taxes, although no such amounts have been recognized in the accompanying financial statements. Currently, McMoRan’s major taxing jurisdictions are the United States (federal) and Louisiana. Tax periods open to audit primarily include federal and Louisiana income tax returns subsequent to 2006. Net operating loss amounts prior to this time are also subject to audit.

8. OIL AND GAS ACTIVITIES

Exploration and Operations.

McMoRan has incurred drilling costs for in-progress and/or unproved exploratory wells totaling $438.7 million at June 30, 2011. In addition, McMoRan’s allocated costs for the working interests in the properties acquired in the PXP Acquisition associated with the current in-progress and unproven wells totaled $659.5 million at June 30, 2011.

In the second quarter of 2011, McMoRan re-perforated the hydrocarbon bearing sands encountered in the Blueberry Hill #9 STK1 offset appraisal well and performed additional production testing. Evaluation of the results from the production test indicated that the well was non-commercial. McMoRan recorded a charge to exploration expense of approximately $37 million for the capitalized costs associated with the Blueberry Hill #9 STK1 well in the second quarter of 2011.

As of June 30, 2011, McMoRan had two wells (Davy Jones initial discovery well and Blackbeard West) with costs that had been capitalized for a period in excess of one year following the completion of the initial exploratory drilling operations. Significant activities are ongoing for the further assessment and development of the Davy Jones discovery well with equipment procurement and other well test preparation activities currently in progress, with completion expected by the end of 2011.

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

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evaluation, and the well was temporarily abandoned.

McMoRan holds approximately 25,000 gross acres within the Blackbeard West unit under a Suspension of Operations (SOO) agreement from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), the terms of which require McMoRan to commence drilling activities by December 31, 2011 to maintain its lease rights to Blackbeard West. McMoRan plans to drill a new well within the Blackbeard West unit on Ship Shoal Block 188 to evaluate the Miocene age sands seen in the Blackbeard East prospect above 25,000 feet. This ultra-deep well, which is expected to commence in the second half of 2011, has a proposed total depth of 26,000 feet. McMoRan’s total investment in Blackbeard West, which includes $27.6 million in allocated costs associated with the PXP property acquisition, totaled $58.9 million at June 30, 2011.

The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block 217, was drilled to a true vertical depth of 21,378 feet in July 2011. Log results indicated the presence of Operc and Gyro sands that McMoRan determined could be pursued in an updip location. The well has been temporarily abandoned to preserve the wellbore and McMoRan is evaluating opportunities to sidetrack or deepen. McMoRan’s total investment in Hurricane Deep, which includes $16.8 million in allocated costs associated with the PXP property acquisition, totaled $54.5 million at June 30, 2011.

If current or future activities are not successful in generating production that will allow McMoRan to recover all or a portion of its investment in any of its in-progress and/or unproven wells, McMoRan may be required to write down its investment in such properties to their estimated fair value. See Note 1 of the 2010 Form 10-K for additional information regarding the periodic assessment of potential impairments to McMoRan’s properties.

As also discussed in Note 1 of the 2010 Form 10-K, when events and circumstances indicate that proved oil and gas property carrying amounts might not be recoverable from estimated future undiscounted cash flows, a reduction of the carrying amount to estimated fair value is required. McMoRan estimates the fair value of its properties using estimated future cash flows based on proved and risk-adjusted probable oil and natural gas reserves as estimated by independent reserve engineers as adjusted for current period production. Future cash flows are determined using published period-end forward market prices adjusted for property-specific price basis differentials, net of estimated future production and development costs and excluding estimated asset retirement and abandonment expenditures. If the undiscounted cash flows indicate that the property is impaired, McMoRan discounts the future cash flows using a discount factor that considers market participants’ expected rates of return for similar type assets if acquired under current market conditions.

The determination of oil and gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent evaluation of the same reserves may result in variations in estimated reserves and related estimates of future cash flows, and these variations may be substantial. If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required.

McMoRan recorded impairment charges totaling $29.2 million and $50.7 million, respectively, during the second quarter and six months ended June 30, 2011 following impairment assessments of the carrying value of its oil and gas properties. The majority of the charges recorded in the second quarter of 2011 ($23.8 million) was related to adjustments to proved reserves following the evaluation of drilling results at a proved undeveloped location. The six months ended June 30, 2011 also included approximately $15.6 million related to a proved undeveloped property which was deemed impaired following unsuccessful attempts to achieve an economically acceptable farm-out arrangement with a third party for development of the property. In the comparable prior year periods McMoRan recorded impairment charges of $13.7 million and $70.7 million, respectively primarily due to declines in market prices for natural gas in the first quarter of 2010 and negative reserve revisions resulting from well

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performance issues encountered at certain properties during the second quarter of 2010. McMoRan considers the fair value measurements used in its impairment evaluations to be derived from Level 3 inputs.

Since the fourth quarter of 2008, declines in market prices for oil and natural gas coupled with other operational factors triggered impairment assessments that ultimately resulted in significant impairment charges for several of McMoRan’s oil and gas property investments. Additional impairment charges may be recorded in future periods if prices weaken, or if other unforeseen operational issues occur that negatively impact McMoRan’s ability to fully recover its current investments in oil and gas properties.

For more information regarding the risks associated with the declines in the future market prices of oil and natural gas and the other factors that could impact current reserve estimates, see Part I, Item 1A. “Risk Factors” included in the 2010 Form 10-K.

2008 Hurricane Activity.

Since the third quarter of 2008, McMoRan has recorded charges of approximately $200 million related to incurred repair costs, property impairments and additional estimated reclamation costs associated with properties damaged by Hurricane Ike. A significant portion of these costs are recoverable under McMoRan’s insurance programs, and aggregate recoveries recorded to date approximate $93 million. Additional recoveries will be recorded as these costs are funded in the future. McMoRan recognized net insurance recoveries of $12.9 million and $29.4 million, respectively, during the second quarter and six months ended June 30, 2011 and recognized net insurance recoveries of $9.2 million in both the second quarter and six months ended June 30, 2010.

Accrued Reclamation Obligations.

For more information regarding McMoRan’s accounting policies for asset retirement obligations see Notes 1 and 15 of the 2010 Form 10-K. A summary of changes in McMoRan’s consolidated discounted asset retirement obligations (including both current and long-term obligations) since December 31, 2010 follows (in thousands):

	Oil and
	Natural Gas			Sulphur
Asset retirement obligation at beginning of year	$	358,624		$	25,266
Liabilities settled		(63,210	)		(6,136	)
Accretion expense		7,175			2,571
Incurred liabilities		-			-
Revision for changes in estimates		35,836	a		1,000
Other		(1,053	)		-
Asset retirement obligations at June 30, 2011	$	337,372		$	22,701

Includes adjustments totaling approximately $18.7 million for the estimated remediation costs of hurricane related damage discovered in the first and second quarters of 2011 during on-going reclamation and abandonment activities at one of McMoRan’s oil and gas properties, the cost of which is reimbursable under McMoRan’s insurance policies when the related reclamation expenditures are incurred.

Since 2007 and through June 30, 2011, McMoRan has incurred over $270 million of reclamation costs to satisfy a significant portion of the asset retirement obligations assumed in an oil and gas property acquisition in 2007, including certain properties damaged in the 2008 hurricanes. In addition, McMoRan expects to incur in excess of $150 million of additional reclamation costs on certain oil and gas properties over the next twelve months. McMoRan’s estimates of existing asset retirement obligations involve inherent uncertainties and are subject to change over time as a result of several factors, including, among others, changes in the industry’s regulatory environment, changes in the cost and availability of required equipment and expertise to complete the work, changes in timing, as well as revisions resulting from other scope expansion matters that develop or become known as reclamation projects are conducted. McMoRan revises its reclamation estimates, as appropriate, when such changes in estimates become known.

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Regulatory and Other Matters.

On April 20, 2010, the Deepwater Horizon , a semi-submersible offshore drilling rig located in the deepwater of the Gulf of Mexico, sank following a catastrophic explosion and fire. This event significantly and adversely disrupted oil and gas exploration activities in the Gulf of Mexico and ultimately resulted in the temporary suspension by the United States government of all deepwater drilling and exploration activity in the Gulf of Mexico. Although the suspension was lifted on October 13, 2010, delays in obtaining drilling permits and compliance with new safety regulations continue to slow new drilling and exploration activity by Gulf of Mexico operators, including operators in shallow waters. McMoRan has continued to advance its exploration and development activities despite a challenging regulatory environment.

While the suspension did not apply to any of McMoRan’s current operations or prospects, new regulations and enhanced safety certifications have been issued for all operations in the Gulf of Mexico. McMoRan completed the necessary initial certifications in June 2010 and is providing required information to secure permits for future drilling. The processing of permits has been slower than experienced prior to the Deepwater Horizon incident, and delays in obtaining permits from the BOEMRE could impact the timing of drilling new wells. While McMoRan has been successful in obtaining a number of permits since September 2010, other permit applications are under review. Uncertainties associated with McMoRan’s ability to obtain necessary permits and/or other regulatory imposed delays could impact future financial results.

McMoRan has significant drilling and other commitments associated with its business strategy. The events described above have resulted in uncertainties in drilling schedules and present challenges in managing ongoing rig commitments. McMoRan incurred idle rig costs approximating $3.8 million during the second quarter of 2011 which was recorded to exploration expense. To partially offset the loss associated with the idle drilling rig, McMoRan recently negotiated an arrangement with a third party to use the drilling rig on a short-term basis. Depending on the required duration of use by the third party, McMoRan expects to incur additional charges approximating $4.0-$6.0 million to reflect the net costs of the drilling rig in excess of anticipated third party reimbursements in the second half of 2011 associated with this drilling rig.

9. OTHER MATERS

8% Preferred Stock Conversions.

McMoRan induced conversion of approximately 8,100 shares of its 8% preferred stock with a liquidation preference of $8.1 million into approximately 1.2 million shares of McMoRan common stock during the six months ended June 30, 2011. McMoRan paid an aggregate of $1.5 million in cash to the holders of these shares during the six months ended June 30, 2011 to induce the early conversions of these shares. Following this transaction, approximately 14,000 shares of McMoRan’s 8% preferred stock remain outstanding.

During the second quarter of 2010, McMoRan privately negotiated the induced conversion of approximately 9,600 shares of its 8% preferred stock with a liquidation preference of $9.6 million into approximately 1.4 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). To induce the early conversions of these shares of 8% preferred stock, McMoRan paid an aggregate of $1.9 million in cash to the holders of these shares, which was recorded as a component of preferred dividends and inducement payments for early conversion of convertible preferred stock in the second quarter of 2010. McMoRan induced conversion of approximately 57,200 shares of its 8% preferred stock with a liquidation preference of $57.2 million into approximately 8.4 million shares of McMoRan common stock during the six months ended June 30, 2010. McMoRan paid an aggregate of $10.8 million in cash to the holders of these shares during the six months ended June 30, 2010 to induce the early conversions of these shares.

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Employee Benefits.

McMoRan provides certain health care and life insurance benefits (Other Benefits) to retired employees. See Note 11 of the 2010 Form 10-K for more information regarding the Other Benefits plan. The components of net periodic benefit cost for McMoRan’s Other Benefits plan follows (in thousands):

	Second Quarter						Six Months
	2011			2010			2011			2010
Service cost	$	14		$	17		$	28		$	34
Interest cost		50			60			100			120
Return on plan assets		-			-			-			-
Amortization of prior service costs
and actuarial gains		(10	)		(9	)		(20	)		(18	)
Net periodic benefit expense	$	54		$	68		$	108		$	136

Comprehensive loss.

McMoRan’s comprehensive loss follows (in thousands):

	Second Quarter						Six Months
	2011			2010			2011			2010
Net loss	$	(39,855	)	$	(16,453	)	$	(55,633	)	$	(69,847	)
Other comprehensive loss:
Amortization of previously unrecognized pension
components, net		(10	)		(9	)		(20	)		(18	)
Comprehensive loss	$	(39,865	)	$	(16,462	)	$	(55,653	)	$	(69,865	)

Subsequent Events Evaluation.

McMoRan evaluated subsequent events for purposes of its June 30, 2011 financial reporting through the date of filing of its quarterly report on Form 10-Q with the Securities and Exchange Commission.

10. GUARANTOR FINANCIAL STATEMENTS

MOXY is an unconditional guarantor of McMoRan’s 11.875% senior notes. See Notes 6 and 18 of the 2010 Form 10-K for additional information regarding these senior notes and MOXY’s guarantee.

The following unaudited consolidating financial information includes information regarding McMoRan, as parent, MOXY and its subsidiaries, as guarantors, and Freeport Energy, as the non-guarantor subsidiary. Included are the condensed consolidating balance sheets at June 30, 2011 and December 31, 2010 and the related condensed consolidating statements of operations and cash flow for the quarter and six months ended June 30, 2011 and 2010, which should be read in conjunction with the Notes to these condensed consolidated financial statements:

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CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)

June 30, 2011

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	15,397	$	749,826	$	97		$	-		$	765,320
Accounts receivable		-		100,317		-			-			100,317
Inventories		-		32,023		-			-			32,023
Prepaid expenses		1,725		4,068		-			-			5,793
Current assets from discontinued
operations		-		-		1,367			-			1,367
Total current assets		17,122		886,234		1,464			-			904,820
Property, plant and equipment, net		-		1,915,413		30			-			1,915,443
Investment in subsidiaries		1,504,803		-		-			(1,504,803	)		-
Amounts due from affiliates		716,184				-			(716,184	)		-
Restricted cash and other
assets		5,444		60,438		-			-			65,882
Long-term assets from discontinued operations		-		-		2,989			-			2,989
Total assets	$	2,243,553	$	2,862,085	$	4,483		$	(2,220,987	)	$	2,889,134

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities :
Accounts payable	$	505	$	107,344	$	186		$	-		$	108,035
Accrued liabilities		1,145		161,766		(158	)		-			162,753
Current portion of debt		74,720		-		-			-			74,720
Current portion of oil and gas
accrued reclamation costs		-		153,636		-			-			153,636
Other current liabilities		14,798		-		-			-			14,798
Current liabilities from discontinued
operations		-		-		10,333			-			10,333
Total current liabilities		91,168		422,746		10,361			-			524,275
Long-term debt		486,309		-		-			-			486,309
Amounts due to affiliates		-		714,001		2,183			(716,184	)		-
Accrued oil and gas reclamation costs		-		183,736		-			-			183,736
Other long-term liabilities		5,546		8,801		1,616			-			15,963
Long-term liabilities from discontinued
operations		-		-		18,321			-			18,321
Total liabilities		583,023		1,329,284		32,481			(716,184	)		1,228,604
Stockholders’ equity (deficit)		1,660,530		1,532,801		(27,998	)		(1,504,803	)		1,660,530
Total liabilities and stockholders’
equity (deficit)	$	2,243,553	$	2,862,085	$	4,483		$	(2,220,987	)	$	2,889,134

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CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2010

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	420	$	904,889	$	375		$	-		$	905,684
Accounts receivable		66		86,450		-			-			86,516
Inventories		-		38,461		-			-			38,461
Prepaid expenses		657		14,821		-			-			15,478
Current assets from discontinued
operations		-		-		702			-			702
Total current assets		1,143		1,044,621		1,077			-			1,046,841
Property, plant and equipment, net		-		1,785,576		31			-			1,785,607
Investment in subsidiaries		1,525,531		-		-			(1,525,531	)		-
Amounts due from affiliates		772,502				-			(772,502	)		-
Restricted cash and other
assets		6,536		57,391		-			-			63,927
Long-term assets from discontinued operations		-		-		2,989			-			2,989
Total assets	$	2,305,712	$	2,887,588	$	4,097		$	(2,298,033	)	$	2,899,364

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities :
Accounts payable	$	444	$	100,163	$	2,051		$	-		$	102,658
Accrued liabilities		8,899		90,784		(320	)		-			99,363
Current portion of debt		74,720		-		-			-			74,720
Current portion of oil and gas
accrued reclamation costs		-		120,970		-			-			120,970
Other current liabilities		5,950		818		-			-			6,768
Current liabilities from discontinued
operations		-		-		13,765			-			13,765
Total current liabilities		90,013		312,735		15,496			-			418,244
Long-term debt		485,256		-		-			-			485,256
Amounts due to affiliates		-		770,373		2,129			(772,502	)		-
Accrued oil and gas reclamation costs		-		237,654		-			-			237,654
Other long-term liabilities		6,106		8,876		1,614			-			16,596
Long-term liabilities from discontinued
operations		-		-		17,277			-			17,277
Total liabilities		581,375		1,329,638		36,516			(772,502	)		1,175,027
Stockholders’ equity (deficit)		1,724,337		1,557,950		(32,419	)		(1,525,531	)		1,724,337
Total liabilities and stockholders’
equity (deficit)	$	2,305,712	$	2,887,588	$	4,097		$	(2,298,033	)	$	2,899,364

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Three Months Ended June 30, 2011

							Freeport					Consolidated
	Parent			MOXY			Energy			Eliminations		McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	155,469		$	-		$	-	$	155,469
Service		-			2,839			-			-		2,839
Total revenues		-			158,308			-			-		158,308
Costs and expenses:
Production and delivery costs		-			51,917			(6	)		-		51,911
Depletion, depreciation and amortization
expense		-			95,338			-			-		95,338
Exploration expenses		-			47,896			-			-		47,896
General and administrative expenses		2,533			8,690			-			-		11,223
Main Pass Energy Hub TM costs		-			-			278			-		278
Insurance recoveries		-			(12,946	)		-			-		(12,946	)
Total costs and expenses		2,533			190,895			272			-		193,700
Operating loss		(2,533	)		(32,587	)		(272	)		-		(35,392	)
Interest expense, net		(2,704	)		-			-			-		(2,704	)
Equity in losses of consolidated
subsidiaries		(34,613	)		-			-			34,613		-
Other income (expense), net		(5	)		235			-			-		230
Loss from continuing operations before
income taxes		(39,855	)		(32,352	)		(272	)		34,613		(37,866	)
Income tax expense		-			-			-			-		-
Loss from continuing operations		(39,855	)		(32,352	)		(272	)		34,613		(37,866	)
Loss from discontinued operations		-			-			(1,989	)		-		(1,989	)
Net loss		(39,855	)		(32,352	)		(2,261	)		34,613		(39,855	)
Preferred dividends and other related
preferred stock costs		(10,343	)		-			-			-		(10,343	)
Net loss applicable to common stock	$	(50,198	)	$	(32,352	)	$	(2,261	)	$	34,613	$	(50,198	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Six Months Ended June 30, 2011

							Freeport					Consolidated
	Parent			MOXY			Energy			Eliminations		McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	289,181		$	-		$	-	$	289,181
Service		-			6,131			-			-		6,131
Total revenues		-			295,312			-			-		295,312
Costs and expenses:
Production and delivery costs		-			99,884			(16	)		-		99,868
Depletion, depreciation and amortization
expense		-			182,008			-			-		182,008
Exploration expenses		-			60,674			-			-		60,674
General and administrative expenses		5,292			21,883			-			-		27,175
Main Pass Energy Hub TM costs		-			-			513			-		513
Insurance recoveries		-			(29,369	)		-			-		(29,369	)
Gain on sale of oil and gas property		-			(900	)		-			-		(900	)
Total costs and expenses		5,292			334,180			497			-		339,969
Operating loss		(5,292	)		(38,868	)		(497	)		-		(44,657	)
Interest expense, net		(8,153	)		-			-			-		(8,153	)
Equity in losses of consolidated													-
subsidiaries		(42,178	)		-			-			42,178		-
Other income (expense), net		(10	)		420			-			-		410
Loss from continuing operations before
income taxes		(55,633	)		(38,448	)		(497	)		42,178		(52,400	)
Income tax expense		-			-			-			-		-
Loss from continuing operations		(55,633	)		(38,448	)		(497	)		42,178		(52,400	)
Loss from discontinued operations		-			-			(3,233	)		-		(3,233	)
Net loss		(55,633	)		(38,448	)		(3,730	)		42,178		(55,633	)
Preferred dividends and other related
preferred stock costs		(22,115	)		-			-			-		(22,115	)
Net loss applicable to common stock	$	(77,748	)	$	(38,448	)	$	(3,730	)	$	42,178	$	(77,748	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Three Months Ended June 30, 2010

							Freeport					Consolidated
	Parent			MOXY			Energy			Eliminations		McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	104,103		$	-		$	-	$	104,103
Service		-			3,938			-			-		3,938
Total revenues		-			108,041			-			-		108,041
Costs and expenses:
Production and delivery costs		-			46,452			(13	)		-		46,439
Depletion, depreciation and amortization
expense		-			57,887			-			-		57,887
Exploration expenses		-			10,434			-			-		10,434
Loss on oil and gas derivative contracts		-			477			-			-		477
General and administrative expenses		1,380			8,996			-			-		10,376
Main Pass Energy Hub TM costs		-			-			242			-		242
Insurance recoveries		-			(9,171	)		-			-		(9,171	)
Gain on sale of oil and gas property		-			(3,455	)		-			-		(3,455	)
Total costs and expenses		1,380			111,620			229			-		113,229
Operating loss		(1,380	)		(3,579	)		(229	)		-		(5,188	)
Interest expense, net		(10,122	)		249			-			-		(9,873	)
Equity in losses of consolidated													-
subsidiaries		(4,946	)		-			-			4,946		-
Other income (expense), net		(5	)		49			-			-		44
Loss from continuing operations before
income taxes		(16,453	)		(3,281	)		(229	)		4,946		(15,017	)
Income tax expense		-			-			-			-		-
Loss from continuing operations		(16,453	)		(3,281	)		(229	)		4,946		(15,017	)
Loss from discontinued operations		-			-			(1,436	)		-		(1,436	)
Net loss		(16,453	)		(3,281	)		(1,665	)		4,946		(16,453	)
Preferred dividends and other related
preferred stock costs		(5,293	)		-			-			-		(5,293	)
Net loss applicable to common stock	$	(21,746	)	$	(3,281	)	$	(1,665	)	$	4,946	$	(21,746	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Six Months Ended June 30, 2010

							Freeport					Consolidated
	Parent			MOXY			Energy			Eliminations		McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	232,949		$	-		$	-	$	232,949
Service		-			7,580			-			-		7,580
Total revenues		-			240,529			-			-		240,529
Costs and expenses:
Production and delivery costs		-			89,249			(25	)		-		89,224
Depletion, depreciation and amortization
expense		-			166,132			-			-		166,132
Exploration expenses		-			22,843			-			-		22,843
Gain on oil and gas derivative contracts		-			(3,268	)		-			-		(3,268	)
General and administrative expenses		2,911			21,208			-			-		24,119
Main Pass Energy Hub TM costs		-			-			575			-		575
Insurance recoveries		-			(9,171	)		-			-		(9,171	)
Gain on sale of oil and gas property		-			(3,455	)		-			-		(3,455	)
Total costs and expenses		2,911			283,538			550			-		286,999
Operating loss		(2,911	)		(43,009	)		(550	)		-		(46,470	)
Interest expense, net		(20,406	)		-			-			-		(20,406	)
Equity in losses of consolidated													-
subsidiaries		(46,529	)		-			-			46,529		-
Other income (expense), net		(1	)		106			-			-		105
Loss from continuing operations before
income taxes		(69,847	)		(42,903	)		(550	)		46,529		(66,771	)
Income tax expense		-			-			-			-		-
Loss from continuing operations		(69,847	)		(42,903	)		(550	)		46,529		(66,771	)
Loss from discontinued operations		-			-			(3,076	)		-		(3,076	)
Net loss		(69,847	)		(42,903	)		(3,626	)		46,529		(69,847	)
Preferred dividends and other related
preferred stock costs		(18,059	)		-			-			-		(18,059	)
Net loss applicable to common stock	$	(87,906	)	$	(42,903	)	$	(3,626	)	$	46,529	$	(87,906	)

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW (UNAUDITED)

Six Months Ended June 30, 2011

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)

Cash flow from operating activities:
Net cash provided by (used in) continuing
operations	$	(16,441	)	$	160,913		$	(409	)	$	144,063
Net cash used in discontinued operations		-			-			(7,923	)		(7,923	)
Net cash provided by (used in) operating
activities		(16,441	)		160,913			(8,332	)		136,140

Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(258,894	)		-			(258,894	)
Gain on sale of oil and gas property		-			900			-			900
Net cash used in investing activities		-			(257,994	)		-			(257,994	)

Cash flow from financing activities:
Dividends paid and conversion inducement		(17,267	)		-			-			(17,267	)
payments on convertible preferred stock
Credit facility refinancing		-			(1,609	)		-			(1,609	)
Proceeds from exercise of stock options		909			-			-			909
Debt and equity issuance costs		(543	)		-			-			(543	)
Investment from parent		(8,000	)		-			8,000			-
Amounts payable to consolidated affiliate		56,319			(56,373	)		54			-
Net cash (used in) provided by financing
activities		31,418			(57,982	)		8,054			(18,510	)

Net increase (decrease) in cash and cash		14,977			(155,063	)		(278	)		(140,364	)
equivalents
Cash and cash equivalents at beginning		420			904,889			375			905,684
of year
Cash and cash equivalents at end of year	$	15,397		$	749,826		$	97		$	765,320

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW (UNAUDITED)

Six Months Ended June 30, 2010

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)

Cash flow from operating activities:
Net cash provided by (used in) continuing
operations	$	20,720		$	73,060		$	(83	)	$	93,697
Net cash used in discontinued operations		-			-			(2,164	)		(2,164	)
Net cash provided by (used in) operating
activities		20,720			73,060			(2,247	)		91,533

Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(101,436	)		-			(101,436	)
Gain on sale of oil and gas property		-			2,920			-			2,920
Net cash used in investing activities		-			(98,516	)		-			(98,516	)

Cash flow from financing activities:
Dividends paid and conversion inducement		(17,589	)		-			-			(17,589	)
payments on convertible preferred stock
Proceeds from exercise of stock options		182			-			-			182
Investment from parent		(2,300	)		-			2,300			-
Net cash (used in) provided by financing
activities		(19,707	)		-			2,300			(17,407	)

Net increase (decrease) in cash and cash		1,013			(25,456	)		53			(24,390	)
equivalents
Cash and cash equivalents at beginning		16			241,400			2			241,418
of year
Cash and cash equivalents at end of year	$	1,029		$	215,944		$	55		$	217,028

11. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan sustained losses from continuing operations totaling $52.4 million for the six months ended June 30, 2011, which were inadequate to cover its fixed charges of $28.9 million for the six months ended June 30, 2011. McMoRan sustained losses from continuing operations totaling $66.8 million for the six months ended June 30, 2010, which were inadequate to cover its fixed charges of $23.6 million for the six months ended June 30, 2010. For this calculation, earnings consist of losses from continuing operations and fixed charges. Fixed charges include interest and that portion of rent deemed representative of interest.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of McMoRan Exploration Co.:

We have reviewed the condensed consolidated balance sheet of McMoRan Exploration Co. (a Delaware corporation) as of June 30, 2011, and the related consolidated statements of operations for the three-and six-month periods ended June 30, 2011 and 2010 and cash flow for the six month periods ended June 30, 2011 and 2010, and the consolidated statement of equity for the six month period ended June 30, 2011. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of McMoRan Exploration Co. as of December 31, 2010, and the related consolidated statements of operations, cash flow and changes in stockholders’ equity (deficit) for the year then ended (not presented herein), and in our report dated February 28, 2011, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2010, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ ERNST & YOUNG LLP

New Orleans, Louisiana

August 5, 2011

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

OVERVIEW

In management’s discussion and analysis “we,” “us,” and “our” refer to McMoRan Exploration Co. and its wholly owned consolidated subsidiaries, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy). You should read the following discussions in conjunction with our consolidated financial statements, the related discussion and analysis of financial condition and results of operations and our discussion of “Business and Properties” in our Annual Report on Form 10-K for the year ended December 31, 2010 (2010 Form 10-K) filed with the Securities and Exchange Commission. The results of operations reported and summarized below are not necessarily indicative of future operating results. Unless otherwise specified, all references to Notes refers to Notes to Consolidated Financial Statements included elsewhere in this Form 10-Q. Also see the 2010 Form 10-K for a glossary of definitions for some of the oil and gas industry terms we use in this Form 10-Q.

We engage in the exploration, development and production of oil and natural gas in the shallow waters (less than 500 feet of water) of the Gulf of Mexico and onshore in the Gulf Coast area of the United States. Our exploration strategy is focused on targeting large structures on the “deep gas play,” and on the “ultra-deep play.” Deep gas prospects target large deposits at depths typically between 15,000 and 25,000 feet. Ultra-deep prospects target objectives at depths typically below 25,000 feet. We have one of the largest acreage positions in the shallow waters of the Gulf of Mexico and Gulf Coast areas which are our regions of focus. We have rights to approximately 850,000 gross acres, including over 200,000 gross acres associated with the ultra-deep gas play below the salt weld. Our focused strategy enables us to make efficient use of our geological, engineering and operational expertise in these areas where we have more than 40 years of operating experience. We also believe that the scale of our operations in the Gulf of Mexico allows us to realize certain operating synergies and provides a strong platform from which to pursue our business strategy. Our oil and gas operations are conducted through MOXY, our principal operating subsidiary.

On December 30, 2010, we completed the acquisition of Plains Exploration & Production Company’s (PXP) shallow water Gulf of Mexico shelf assets (PXP Acquisition). Under the terms of the transaction, we issued 51 million shares of common stock and paid $75.0 million cash to PXP, with total consideration for the transaction of approximately $1 billion based on the value of our common stock on the closing date. In addition, the purchase price included additional consideration associated with estimated revenues, expenses and capital expenditures attributable to the acquired properties from the August 1, 2010 effective date through the December 30, 2010 closing date, and the assumption of related asset retirement obligations. The substantial majority of properties acquired from PXP represented their interests in certain deep gas and ultra-deep exploration projects that, prior to the transaction, were jointly owned by us and PXP. The acquisition purchase price was allocated to the properties acquired with approximately 19% allocated to proved properties and the remaining portion allocated to unevaluated oil and gas properties. Concurrent with the PXP Acquisition, we issued $700 million of 5.75% Convertible Perpetual Preferred Stock (5.75% preferred stock) and $200 million of 4% Convertible Senior Notes (4% senior notes). See notes 2, 6, and 8 of the 2010 Form 10-K for additional information regarding the PXP Acquisition and related financing transactions.

The PXP Acquisition increased our scale of operations on the Gulf of Mexico shelf, consolidated our ownership in core focus areas, expanded our participation in future production from our deep gas and ultra-deep exploration and development programs and increased current reserves and production. In addition, we expect to continue to benefit from our positive relationship with PXP through PXP’s significant shareholding position in our company.

During the six months ended June 30, 2011, we invested $258.9 million on capital-related projects primarily associated with our exploration activities. Depending on drilling results and follow on development opportunities, we expect 2011 capital expenditures to approximate $500 million including approximately $300 million in exploration and $200 million in development spending. During the six months ended June 30, 2011, we also incurred $42.2 million of net abandonment expenditures. We plan to spend approximately $160 million in 2011 for the abandonment and removal of oil and gas structures in the Gulf of Mexico, a portion of which is expected to be recovered through insurance reimbursements.

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Capital spending will continue to be driven by opportunities and will be managed based on market conditions. We plan to fund our capital spending through available cash, cash flow from operations and participation by partners in exploration and development projects. We continue to monitor the global financial and credit markets, as well as the fluctuations in oil and natural gas market prices, all of which may ultimately have a material effect on our business and overall business strategy. We will continue to evaluate and respond to any impact these conditions may have on our operations.

North American Natural Gas and Oil Market Environment

Our second quarter revenues were derived 55 percent from oil and 45 percent from natural gas. North American natural gas averaged $4.38 per MMbtu during the second quarter of 2011. The spot price for natural gas was $4.26 per MMbtu on August 3, 2011. The average oil price for the second quarter of 2011 was $102.58 per barrel, and the spot price for oil was $91.93 per barrel on August 3, 2011. Future oil and natural gas prices are subject to change and these changes are not within our control (see Item 1A. “Risk Factors” included in the 2010 Form 10-K).

OPERATIONAL ACTIVITIES

Regulatory and Other Matters

On April 20, 2010, the Deepwater Horizon , a semi-submersible offshore drilling rig located in the deepwater of the Gulf of Mexico, sank following a catastrophic explosion and fire. This event significantly and adversely disrupted oil and gas exploration activities in the Gulf of Mexico and ultimately resulted in the temporary suspension by the United States government of all deepwater drilling and exploration activity in the Gulf of Mexico. Although the suspension was lifted on October 13, 2010, delays in obtaining drilling permits and compliance with new safety regulations continue to slow new drilling and exploration activity by Gulf of Mexico operators, including operators in shallow waters. We have continued to advance our exploration and development activities despite a challenging regulatory environment.

While the suspension did not apply to any of our current operations or prospects, new regulations and enhanced safety certifications have been issued for all operations in the Gulf of Mexico. We completed the necessary initial certifications in June 2010 and are providing required information to

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secure permits for future drilling. The processing of permits has been slower than experienced prior to the Deepwater Horizon incident, and delays in obtaining permits from the BOEMRE could impact the timing of drilling new wells. While we have been successful in obtaining a number of permits since September 2010, other permit applications are under review. Uncertainties associated with our ability to obtain necessary permits and/or other regulatory imposed delays could impact our future financial results.

We have significant drilling and other commitments associated with our business strategy. The events described above have resulted in uncertainties in drilling schedules and present challenges in managing ongoing rig commitments. We incurred idle rig costs approximating $3.8 million during the second quarter of 2011 which was recorded to exploration expense. To partially offset the loss associated with the idle drilling rig, we recently negotiated an arrangement with a third party to use the drilling rig on a short-term basis. Depending on the required duration of use by the third party, we expect to incur additional charges approximating $4.0-$6.0 million to reflect the net costs of the drilling rig in excess of anticipated third party reimbursements in the second half of 2011 associated with this drilling rig.

Production Update

Second-quarter 2011 production averaged 197 MMcfe/d net to us, compared with 165 MMcfe/d in the second quarter of 2010. Production in the second quarter of 2011 was higher than previously reported estimates of 190 MMcfe/d in April 2011 because of favorable production performance. Production is expected to average approximately 180 MMcfe/d in the third quarter of 2011 and 185 MMcfe/d for the year, higher than the previous 2011 annual estimate of 175 MMcfe/d. Estimated production rates are dependent on the timing of planned recompletions, production performance, weather and other factors.

Production from the Flatrock field averaged a gross rate of approximately 172 MMcfe/d (70 MMcfe/d net) in the second quarter of 2011. We own a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

We successfully commenced production from the Laphroaig No. 2 well in St. Mary Parish, Louisiana in late April 2011. Production from the Laphroaig No. 2 well averaged a gross rate of approximately 50 MMcfe/d (15 MMcfe/d net) in May and June of 2011. We own a 38.4 percent working interest and a 29.5 percent net revenue interest in the Laphroaig No. 2 well.

Oil and Gas Activities

Shallow Water Ultra-Deep Exploration Activities . Since 2008, we have actively pursued large ultra-deep targets located in the shallow waters of the Gulf of Mexico below the salt weld (i.e. listric fault) at depths generally below 25,000 feet. The data gained to date from four wells confirm our geologic model and the highly prospective nature of this emerging geologic trend. Prior to our involvement in the ultra-deep, there had been only two wells drilled on the shelf targeting these objectives; one did not reach its targeted depth and the other was outside our focus area. Our results to date have indicated the potential for large accumulations of hydrocarbons at these deeper depths in the shallow waters of the Gulf of Mexico.

Our activities to date have confirmed that drilling below the salt weld on the Gulf of Mexico shelf can be achieved safely. In addition, the data indicate the presence below the salt weld of geologic formations including Middle/Lower Miocene, Wilcox, Frio, Tuscaloosa and Cretaceous carbonate. These formations have been prolific onshore, in the deepwater Gulf of Mexico and in international locations. We intend to conduct further drilling and flow testing to determine the ultimate potential of this emerging geologic trend.

The Davy Jones offset appraisal well (Davy Jones No. 2), located on South Marsh Island Block 234, two and a half miles southwest of the Davy Jones No. 1 discovery well, was drilled to a total depth of 30,546 feet. Log results above 27,300 feet confirmed 120 net feet of hydrocarbon bearing Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect.

In June 2011, results from wireline logs of the Cretaceous section below 27,300 feet indicated that the Davy Jones No. 2 well encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. Flow testing will be required to confirm the potential hydrocarbons and flow rates. A 6 5/8 inch production liner has been set to 30,511 feet and the well has been temporarily abandoned. We are evaluating development options and expect to commence

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completion of the No. 2 well for flow testing in the second quarter of 2012. We are also considering updip locations in a subsequent well to the north to evaluate the Tuscaloosa sands and Lower Cretaceous carbonates higher on the Davy Jones structure.

The Tuscaloosa sands are correlative with the prolific Tuscaloosa trend onshore South Louisiana and the carbonate section may be analogous to productive fields located offshore and onshore Mexico in the southern Gulf of Mexico. These potential hydrocarbon bearing zones are the first Cretaceous sandstones and limestones encountered offshore Central Louisiana on the Gulf of Mexico shelf. We believe the combination of productive Wilcox and Cretaceous intervals on the same structure could enhance the value of Davy Jones and the prospectivity of our other ultra-deep prospects on its acreage position within the Davy Jones trend.

As previously reported, in January 2010 we logged 200 net feet of pay in multiple Wilcox sands in the Davy Jones No. 1 well on South Marsh Island Block 230. In March 2010, a production liner was set and the well was temporarily abandoned to prepare for completion. We are preparing to complete and flow test the No. 1 well in late 2011.

Davy Jones involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). We hold a 60.4 percent working interest and a 47.9 percent net revenue interest in Davy Jones. Our total investment in Davy Jones, which includes $444.5 million in allocated costs associated with the PXP property acquisition, totaled $619.4 million at June 30, 2011.

Following a mechanical issue at the Blackbeard East well encountered during the first quarter 2011, we commenced operations in July 2011 to drill a by-pass of the Blackbeard East ultra-deep exploration well at approximately 30,700 feet to evaluate targets in the Eocene. The well is permitted to 34,000 feet. Based on interpretations of drilling data obtained prior to the mechanical issue, we believe the well encountered Sparta sands in the Eocene, which are younger than the Wilcox. Sparta sands are productive onshore in South Louisiana. Wireline logs will be required to evaluate this interval.

As reported in January 2011, wireline logs indicated that Blackbeard East encountered hydrocarbon bearing sands in the Oligocene (Frio) with good porosity below 30,000 feet. We are considering down dip drilling opportunities on the flanks of the structure to evaluate this section further. This is the first hydrocarbon bearing Frio sand encountered either on the Gulf of Mexico shelf or in the deepwater offshore Louisiana. The Frio sand section below 30,000 feet is in addition to the 178 net feet of hydrocarbons in the Miocene sands above 25,000 feet announced in December 2010 at Blackbeard East. 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. We hold a 70.0 percent working interest and a 56.2 percent net revenue interest in the well. Our total investment in Blackbeard East, which includes $119.9 million in allocated costs associated with the PXP property acquisition, totaled $216.1 million at June 30, 2011.

The Lafitte ultra-deep exploration well commenced drilling on October 3, 2010 and is currently drilling below 25,500 feet towards a proposed total depth of 29,950 feet. Lafitte is located on Eugene Island Block 223 in 140 feet of water. The well is targeting Miocene objectives and possibly Oligocene (Frio) sections below the salt weld. We hold a 72.0 percent working interest and 58.3 percent net revenue interest in Lafitte. Our total investment in Lafitte, which includes $35.9 million in allocated costs associated with the PXP property acquisition, totaled $100.2 million at June 30, 2011.

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.

We hold approximately 25,000 gross acres within the Blackbeard West unit under a Suspension of Operations (SOO) agreement from the BOEMRE, the terms of which require us to commence drilling by December 31, 2011 to maintain our lease rights to Blackbeard West. We plan to drill a new well within the Blackbeard West unit on Ship Shoal Block 188 to evaluate the Miocene age sands seen in the Blackbeard East

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prospect above 25,000 feet. This ultra-deep well, which is expected to commence in the second half of 2011, has a proposed total depth of 26,000 feet. The Ship Shoal Block 188 location is approximately 4 miles west of the Blackbeard West #1 well on South Timbalier Block 168. We hold a 67.3 percent working interest and 51.5 percent net revenue interest in the Blackbeard West well on Ship Shoal Block 188. Our total investment in Blackbeard West, which includes $27.6 million in allocated costs associated with the PXP property acquisition, totaled $58.9 million at June 30, 2011.

Shallow Water Deep Gas Exploration and Development Activities . In addition to the ultra-deep play on the Gulf of Mexico shelf, our exploration strategy is also focused on the “deep gas play.” Deep gas prospects target large Miocene age deposits above the salt weld (i.e. listric fault) at depths typically between 15,000 to 25,000 feet.

The Boudin deep gas exploration well commenced drilling on February 27, 2011 and is drilling below 21,000 feet. Boudin, which is located in 20 feet of water on Eugene Island Block 26, has a proposed total depth of 23,100 feet and will test Miocene objectives. We hold a 53.5 percent working interest and a 42.4 percent net revenue interest in Boudin. Our total investment in Boudin, which includes $14.8 million in allocated costs associated with the PXP property acquisition, totaled $49.1 million at June 30, 2011.

The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block 217, was drilled to a true vertical depth of 21,378 feet in July 2011. Log results indicated the presence of Operc and Gyro sands that we determined could be pursued in an updip location. The well has been temporarily abandoned to preserve the wellbore and we are evaluating opportunities to sidetrack or deepen. Our total investment in Hurricane Deep, which includes $16.8 million in allocated costs associated with the PXP property acquisition, totaled $54.5 million at June 30, 2011. Our investment is expected to be reduced by approximately $11 million for reimbursable costs associated with our insurance programs.

The Brazos A-23 development well commenced drilling on February 13, 2011, and was drilled to a total depth of 15,946 feet. This traditional shelf well targeted proved undeveloped reserves updip from logged pay zones. Log evaluation indicated that the well encountered 30 net feet of hydrocarbon bearing sands and a protective liner has been set. The well has been temporarily abandoned while future plans are developed. Evaluation of the well’s drilling results resulted in adjustments to previously estimated reserves, and we recorded a $23.8 million impairment charge in the second quarter to reduce the carrying value of the Brazos A-23 well to $17.4 million.

In the second quarter of 2011, we re-perforated the hydrocarbon bearing sands encountered in the Blueberry Hill #9 STK1 offset appraisal well and performed additional production testing. Evaluation of the results from the production test indicated that the well was non-commercial. We recorded a charge to exploration expense of approximately $37 million for the capitalized cost associated with the Blueberry Hill #9 STK1 well in the second quarter of 2011.

Acreage Position

As of June 30, 2011, we owned or controlled interests in 437 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 0.85 million gross acres (0.53 million acres net to our interests). Our acreage position includes 0.74 million gross acres (0.46 million acres net to our interests) located on the outer continental shelf of the Gulf of Mexico. This acreage position includes over 200,000 gross acres associated with our ultra-deep gas play. Less than 0.1 million of our net leasehold interests are scheduled to expire in the remainder of 2011 (considering our being able to extend lease terms through drilling or other means prior to expiration). We also hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to other oil and gas exploration companies but that will partially revert to us upon the achievement of specified production quantity thresholds or the achievement of specified net production proceeds.

RESULTS OF OPERATIONS

Our second quarter 2011 operating loss of $35.4 million reflects (a) impairment charges of $29.2 million for certain fields to reduce their net carrying value to fair value; (b) adjustments totaling

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approximately $20.4 million charged against earnings for asset retirement obligations associated with certain of our oil and gas properties, approximately $8.1 million of which is covered for future reimbursement under our insurance program; (c) $12.9 million for net insurance recoveries associated with insured hurricane-related losses (d) $2.9 million in charges related to stock-based compensation expense; and (e) $36.8 million in charges to exploration expense primarily related to the Blueberry Hill well.

Our operating loss of $44.7 million for the first six months ended June 30, 2011 reflects (a) impairment charges of $50.7 million for certain fields to reduce their net carrying value to fair value; (b) adjustments totaling approximately $35.1 million charged against earnings for asset retirement obligations associated with certain of our oil and gas properties, approximately $18.7 million of which is covered for future reimbursement under our insurance program; (c) $29.4 million for net insurance recoveries associated with insured hurricane-related losses (d) $12.8 million in charges related to stock-based compensation expense; and (e) $38.9 million in charges to exploration expense primarily related to the Blueberry Hill well.

Our second quarter 2010 operating loss of $5.2 million reflects (a) impairment charges of $13.7 million for certain fields to reduce their net carrying value to fair value; (b) $2.9 million in charges to exploration expense primarily related to the Blueberry Hill appraisal well; (c) $1.9 million of inducement payments related to our 8% Convertible Perpetual Preferred Stock (8% preferred stock); and (d) $0.5 million of net losses on oil and gas derivative contracts (Note 6). These charges are partially offset by (a) a $9.2 million gain associated with our share of a partial payment for insured losses related to the September 2008 hurricanes and (b) a $3.5 million gain on the sale of an oil and gas property.

Our operating loss of $46.5 million for the six months ended June 30, 2010 reflects (a) impairment charges of $70.7 million for certain fields to reduce their net carrying value to fair value; (b) $10.8 million of inducement payments related to our 8% preferred stock; and (c) $7.5 million in charges to exploration expense primarily related to the Blueberry Hill appraisal well. These charges are offset by (a) a $9.2 million gain associated with our share of a partial payment for insured losses related to the September 2008 hurricanes; (b) a $3.5 million gain on the sale of an oil and gas property; and (c) $3.3 million of net gains on oil and gas derivative contracts (Note 6).

Summarized operating data are as follows:

	Second Quarter		Six Months
	2011	2010	2011	2010
Sales volumes:
Gas (thousand cubic feet, or Mcf)	11,600,800	9,802,800	23,270,300	21,041,600
Oil (barrels)	778,400	626,400	1,465,100	1,317,900
Plant products (per Mcf equivalent) a	1,642,800	1,447,600	3,381,300	3,196,600
Average realizations b
Gas (per Mcf)	$ 4.71	$ 4.66	$ 4.62	$ 5.12
Oil (per barrel)	109.08	76.20	103.31	76.28

Results include approximately $15.8 million and $29.8 million of revenues associated with plant products (ethane, propane, butane, etc.) during the second quarter and six months ended June 30, 2011, respectively. Plant product revenues for the comparable prior year periods totaled $10.6 million and $24.5 million. One Mcf equivalent is determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

b.	Excludes the impact of gains and losses on derivative contracts in 2010.

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Oil and Gas Operations

Revenues. A summary of increases (decreases) in our oil and natural gas revenues between the periods follows (in thousands):

	Second			Six
	Quarter			Months
Oil and natural gas revenues – prior year period	$	104,103	$	232,949
Increase (decrease)
Price realizations:
Natural gas		580		(11,635	)
Oil and condensate		25,593		39,602
Sales volumes:
Natural gas		8,379		11,411
Oil and condensate		11,582		11,228
Plant products revenues		5,188		5,261
Other		44		365
Oil and natural gas revenues – current year period	$	155,469	$	289,181

Our oil and natural gas sales volumes totaled 17.9 billion cubic feet of natural gas equivalent (Bcfe) in the second quarter of 2011, a 19 percent increase from the 15.0 Bcfe of sales volume generated in the second quarter of 2010. Average realizations received for both oil and natural gas sold during the second quarter of 2011 increased 43 percent for oil and one percent for natural gas compared to amounts received in 2010 (see “—North American Natural Gas and Oil Market Environment” above). Revenues from plant products totaled $15.8 million in the second quarter of 2011 compared with $10.6 million in the prior year period. Our service revenues totaled $2.8 million in the second quarter of 2011 and $3.9 million in the same period for 2010.

Our oil and natural gas sales volumes totaled 35.4 Bcfe and 32.1 Bcfe in the six months ended June 30, 2011 and 2010, respectively. Average realizations received for both oil and natural gas sold during the six months ended June 30, 2011 increased 35 percent for oil and decreased 10 percent for natural gas compared to amounts received in 2010 (see “—North American Natural Gas and Oil Market Environment” above). Revenues from plant products totaled $29.8 million in the six months ended June 30, 2011 compared with $24.5 million in the prior year period. Our service revenues totaled $6.1 million in the six months ended June 30, 2011 and $7.6 million in the same period for 2010.

Production and delivery costs. The following table reflects our production and delivery costs for the second quarter and six months ended June 30, 2011 and 2010 (in millions, except per Mcfe amounts):

	Second Quarter				Six Months
		Per		Per		Per		Per
	2011	Mcfe	2010	Mcfe	2011	Mcfe	2010	Mcfe
Lease operating expense	$28.4	$1.58	$26.8	$1.79	$58.3	$1.65	$53.8	$1.67
Workover costs	11.6	0.64	5.3	0.35	17.4	0.49	7.6	0.24
Hurricane related expenses	-	-	2.1	0.14	0.1	0.00	2.6	0.08
Insurance	4.9	0.28	6.5	0.43	11.1	0.31	13.3	0.41
Transportation and production taxes	6.9	0.39	5.3	0.35	12.4	0.35	11.7	0.37
Other	0.1	0.01	0.4	0.03	0.6	0.02	0.2	0.01
Total production and delivery costs	$51.9	$2.90	$46.4	$3.09	$99.9	$2.82	$89.2	$2.78

Lease operating expense (LOE) increased approximately $1.6 million and $4.5 million, respectively, in the second quarter and six months ended June 30, 2011 from the comparable prior periods primarily reflecting the impact of the operations of the assets acquired in the PXP Acquisition ($3.0 million of LOE on 4.8 Bcfe of production in the second quarter of 2011 and $6.3 million of LOE on 9.5 Bcfe of production in the first six months of 2011). The assets acquired in the PXP Acquisition generated approximately 27% and 37% of our total production volumes in the second quarter and six months ended June 30, 2011, respectively. Workover costs increased approximately $6.3 million and $9.8 million in the

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second quarter and six months ended June 30, 2011, respectively compared to the 2010 periods, the majority of which was due to certain regulatory related compliance repairs incurred at our Main Pass 299 facility. Transportation, production taxes, and plant product fees increased by approximately $1.6 million in the second quarter of 2011 compared to the 2010 period and $0.7 million in the first six months of 2011 compared to the 2010 period primarily due to the impact of the additional assets acquired in the PXP Acquisition.

Market insurance premium rates for operators in the Gulf of Mexico have increased significantly in recent years following hurricane events and more recently, the Deepwater Horizon incident in April 2010. In addition, the coverage limits for certain types of catastrophic events, such as hurricanes, have become significantly more restrictive. Because of this and in consideration of our on-going efforts to mitigate our exposure to the costs of storm-related structural damage through our aggressive reclamation program to remove platforms and related structures for non-productive wells, we did not obtain coverage for windstorm perils in the recent renewal of our annual insurance program. We maintained coverage for well control up to $150 million for all conventional wells and up to $250 million for ultra-deep wells. Both the limits of coverage and deductibles under this policy are scaled to our working interest in the covered location. We also renewed our Oil Spill Financial Responsibility policy coverage which has a $105 million limit for our Main Pass 299 oil production operations and a $35 million limit for our other producing operations. For additional information related to risks associated with our insurance coverage, see Part II, Item 1A. “Risk Factors” included in this quarterly report on Form 10-Q for the quarter ended June 30, 2011.

Depletion, depreciation and amortization expense . The following table reflects the components of our depletion, depreciation and amortization (DD&A) expense for the second quarter and six months ended June 30, 2011 and 2010 (in millions, except per Mcfe amounts):

	Second Quarter				Six Months
		Per		Per		Per		Per
	2011	Mcfe	2010	Mcfe	2011	Mcfe	2010	Mcfe
Depletion and depreciation expense	$41.9	$2.34	$39.9	$2.66	$88.6	$2.51	$86.4	$2.69
Accretion expense	24.2	1.35	4.3	0.28	42.7	1.20	9.0	0.28
Impairment charges/losses	29.2	1.63	13.7	0.92	50.7	1.43	70.7	2.20
Total	$95.3	$5.32	$57.9	$3.86	$182.0	$5.14	$166.1	$5.17

Our depletion, depreciation and amortization rates are directly affected by estimates of proved reserve quantities, which are subject to revisions over time as changes in reserve estimates and fluctuations in the recorded amounts of property, plant and equipment and asset retirement obligations occur.

The increase in accretion expense in the second quarter and six months ended June 30, 2011 compared to the 2010 periods primarily resulted from $35.1 million of year to date adjustments to oil and gas property asset retirement obligations, approximately $18.7 million of which relates to the estimated remediation costs of hurricane-related damage discovered in the first quarter of 2011 during on-going reclamation and abandonment activities at one of our oil and gas properties. The cost of this hurricane-related reclamation is expected to be reimbursed under our insurance policies when the related reclamation expenditures are incurred.

Since 2007 and through June 30, 2011, we have incurred over $270 million of reclamation costs to satisfy a significant portion of the asset retirement obligations assumed in an oil and gas property acquisition in 2007, including certain properties damaged in the 2008 hurricanes. In addition, we expect to incur in excess of $150 million of additional reclamation costs on certain oil and gas properties over the next twelve months. Our estimates of existing asset retirement obligations involve inherent uncertainties and are subject to change over time as a result of several factors, including, among others, changes in the industry’s regulatory environment, changes in the cost and availability of required equipment and expertise to complete the work, changes in timing, as well as revisions resulting from other scope expansion matters that develop or become known as reclamation projects are conducted. We revise our reclamation estimates, as appropriate, when such changes in estimates become known.

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Accounting rules require the carrying value of proved oil and gas property costs to be assessed for possible impairment under certain circumstances and reduced to fair value by a charge to earnings if impairment is deemed to have occurred. Conditions affecting current and estimated future cash flows that could require impairment charges include, but are not limited to, lower than anticipated oil and natural gas prices, decreased production, increased development, production and reclamation costs and downward revisions of reserve estimates. We recorded impairment charges of $29.2 million during the second quarter of 2011. The majority of these charges ($23.8 million) related to adjustments to proved reserves following the evaluation of drilling results at a proved undeveloped location. We recorded impairment charges of $50.7 million during the first six months of 2011, which in addition to the second quarter 2011 impairment charges, also included a $15.6 million impairment charge related to one proved undeveloped property which was deemed impaired following unsuccessful attempts to achieve an economically acceptable farm-out arrangement with a third party for the development of reserves assigned to that property. Due to the decline in market prices for oil and natural gas and negative reserve revisions resulting from well performance issues encountered at certain properties, we recorded impairment charges of $13.7 million and $70.7 million, respectively, in the second quarter and six months ended June 30, 2010.

As more fully explained in Part I, Item 1A. “Risk Factors” in our 2010 Form 10-K, any one or more of the conditions described above could require additional impairment charges to be recorded in future periods.

Exploration Expenses. Summarized exploration expenses are as follows (in millions):

	Second Quarter						Six Months
	2011			2010			2011			2010
Geological and geophysical
including 3-D seismic purchases a	$	4.1		$	2.0		$	10.9		$	9.0
Non-productive exploratory costs, including
related lease costs		36.8	b		2.9	c		38.9	b		7.5	c
Other d		7.0			5.5			10.9			6.3
	$	47.9		$	10.4		$	60.7		$	22.8

Includes compensation costs associated with outstanding stock-based awards totaling $1.3 million in the second quarter of 2011 and $5.8 million in the six months ended June 30, 2011 compared with $1.3 million and $5.9 million of compensation costs during comparable periods in 2010 (see “Stock-Based Compensation” below).

b.	Includes well costs associated with the Blueberry Hill #9 STK1 well determined to be noncommercial during the second quarter of 2011.

c.	Includes costs of the Blueberry Hill offset appraisal well incurred below 19,000 feet. Results below 19,000 feet were determined to be non-commercial, and we commenced sidetracking efforts in April 2010 to a location southwest of the pay sands seen in 2009.

Includes $1.1 million and $4.2 million in drilling related insurance costs for the second quarter and six months ended June 30, 2011, respectively. Includes $3.8 million of drilling rig charges in the second quarter and six months ended June 30, 2011. Includes $4.4 million of insurance costs attributable to our exploration drilling activities for the second quarter and six months ended June 30, 2010.

Other Financial Results

Operating.

General and administrative expense totaled $11.2 million in the second quarter of 2011 and $27.2 million for the six months ended June 30, 2011 compared with $10.4 million in the second quarter of 2010 and $24.1 million for the six months ended June 30, 2010. The increase in these costs for the six month comparative periods is primarily related to $0.7 million in higher compensation costs during 2011, $1.3 million in higher franchise taxes, and $1.2 million in higher legal costs.

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In the second quarter and six months ended June 30, 2010, we recorded net $0.5 million in losses and $3.3 million in gains, respectively, associated with our oil and gas derivative contracts, all of which matured on December 31, 2010.

Hurricanes Gustav and Ike impacted Gulf of Mexico operations in September 2008. Although there was no significant damage to our properties resulting from Hurricane Gustav, Hurricane Ike caused significant structural damage to several platforms in which we had an investment interest. Since the third quarter of 2008, we have recorded charges of approximately $200 million related to incurred repair costs, property impairments and additional estimated reclamation costs associated with the damaged properties. A significant portion of these costs are recoverable under our insurance programs, and aggregate recoveries recorded to date approximate $93 million. Additional recoveries will be recorded as these costs are funded in the future. We recorded insurance recoveries of $12.9 million and $29.4 million in the second quarter and six months ended June 30, 2011, respectively. We received net insurance proceeds of $9.2 million in the second quarter and six months ended June 30, 2010.

In the six months ended June 30, 2011, we recorded a $0.9 million gain on the sale of one of our Gulf of Mexico oil and gas properties. In the second quarter and six months ended June 30, 2010, we recorded a $3.5 million gain on the sale of one of our Gulf of Mexico oil and gas properties.

Stock-Based Compensation. Compensation cost charged against earnings for stock-based awards is as follows (in thousands):

	Second Quarter				Six Months
	2011		2010		2011		2010

General and administrative expenses	$	1,639	$	1,594	$	6,872	$	6,524
Exploration expenses		1,305		1,324		5,837		5,919
Main Pass Energy Hub costs		22		51		105		214
Total stock-based compensation cost	$	2,966	$	2,969	$	12,814	$	12,657

On February 7, 2011, our Board of Directors granted 1,737,500 stock options to its employees at an exercise price of $17.25 per share, including immediately exercisable options for an aggregate of 445,000 shares. Options representing 400,000 of these 445,000 shares were issued to our Co-Chairmen in lieu of cash compensation in 2011. The weighted average per share value of the 1,857,500 options granted during the six months ended June 30, 2011 was $10.76. We recorded $7.4 million in charges related to immediately vested stock options in the first six months of 2011. These charges included the compensation costs associated with the immediately exercisable options and the compensation costs related to stock options granted to retiree-eligible employees, which resulted in one-year’s compensation expense being immediately recognized at the effective date of the stock option grant. On February 1, 2010, our Board of Directors granted 1,766,500 stock options to its employees at an exercise price of $15.73 per share. The weighted average per share value of the 1,816,500 options granted during the six months ended June 30, 2010 was $10.18.

As of June 30, 2011, total compensation cost related to unvested, approved stock option awards not yet recognized in earnings was approximately $20.3 million, which is expected to be recognized over a weighted average period of approximately one year.

Non-Operating.

Interest expense, net of amounts capitalized, totaled $2.7 million in the second quarter of 2011 and $8.2 million for the six months ended June 30, 2011 compared with $9.9 million in the second quarter of 2010 and $20.4 million for the six months ended June 30, 2010. Capitalized interest totaled $11.6 million in the second quarter of 2011, $1.9 million in the second quarter of 2010, $20.5 million for the six months ended June 30, 2011 and $3.1 million for the six months ended June 30, 2010.

Discontinued Operations.

Our discontinued operations incurred net losses of $2.0 million in the second quarter of 2011 and

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$ 3.2 million for the six months ended June 30, 2011 compared with losses of $1.4 million in the second quarter of 2010 and $3.1 million for the six months ended June 30, 2010. The future estimated closure costs primarily for our former terminal facilities at Port Sulphur, Louisiana approximate $8.7 million at June 30, 2011, which is expect to be funded in the second half of 2011.

CAPITAL RESOURCES AND LIQUIDITY

The table below summarizes our cash flow information by categorizing the information as cash provided by or (used in) operating activities, investing activities and financing activities and distinguishing between our continuing operations and discontinued operations (in millions):

	Six Months Ended
	June 30,
	2011			2010
Continuing operations
Operating	$	144.1		$	93.7
Investing		(258.0	)		(98.5	)
Financing		(18.5	)		(17.4	)


Discontinued operations
Operating	(8.0	)	(2.2	)
Investing	-		-
Financing	-		-

Total cash flow
Operating	136.1		91.5
Investing	(258.0	)	(98.5	)
Financing	(18.5	)	(17.4	)

Six-Month 2011 Cash Flows Compared with Six-Month 2010 Cash Flows

Operating Cash Flows.

Operating cash flow increased $44.6 million for the six months ended June 30, 2011 compared to the same period in 2010 primarily a result of $54.8 million of higher revenue realizations partially offset by approximately $10.6 million of higher production and delivery costs.

Investing Cash Flows.

Our investing cash flows reflect exploration, development and other capital expenditures associated with our oil and gas activities (see “Oil and Gas Activities” above). Our exploration, development and other capital expenditures totaled $258.9 million for the first half of 2011 and $101.4 million for the first half of 2010. This increase is primarily due to our increased working interest in ultra-deep and other exploratory drilling resulting from the PXP Acquisition.

Financing Cash Flows.

Our continuing operations’ financing activities included payments of dividends and inducement payments on our 8% convertible perpetual preferred stock (8% preferred stock) totaling $17.3 million in the first half of 2011. During the first half of 2011, we agreed through a privately negotiated transaction to induce the conversion of approximately 8,100 shares of our 8% preferred stock into approximately 1.2 million shares of our common stock for a payment of $1.5 million. Following this inducement conversion transaction we have approximately 14,000 shares of our 8% preferred stock outstanding as of June 30, 2011. In the first half of 2010, our continuing operations financing activities included payments of dividends and inducement payments on our 8% preferred stock and 6¾% mandatory convertible preferred stock (6¾% preferred stock) totaling $17.6 million during the six months ended June 30, 2010. During this period, we agreed through privately negotiated transactions to induce the conversion of approximately 57,200 shares of 8% preferred stock into approximately 8.4 million shares of common stock for a payment of $10.8 million.

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Senior Secured Revolving Credit Facility

During the second quarter of 2011 we entered into a new variable rate senior secured revolving credit facility (credit facility). The new credit facility is secured by substantially all of MOXY’s oil and gas properties and matures on June 30, 2016, provided that by August 16, 2014 our 11.875% senior notes will have been redeemed or refinanced with senior notes with a term extending at least through 2016; otherwise the maturity date will be August 16, 2014. The credit facility’s borrowing capacity is $150 million, and under certain conditions may be increased up to a capacity of $300 million with additional lender commitments. The terms of the new credit facility are substantially the same as our prior credit agreement. There were no borrowings outstanding under the credit facility during the quarter ended June 30, 2011. After giving effect to a $100 million letter of credit outstanding as surety support to a third party associated with reclamation obligations, availability totaled to $50 million.

Availability under the credit facility is subject to a borrowing base, which is redetermined semi-annually each April and October.

The credit facility includes covenants and other restrictions customary for oil and gas borrowing base credit facilities. We were in compliance with these covenants at June 30, 2011.

Senior Notes and Convertible Senior Notes

The following debt instruments were outstanding as of June 30, 2011 (in millions):

	Amount
11.875% senior notes (due 2014)	$	300.0
5¼% convertible senior notes (due 2011)		74.7
4% convertible senior notes, net of $13.7 discount (due 2017)		186.3
Credit facility		-
Total debt	$	561.0

For additional information regarding our outstanding debt terms and related transactions, see Note 6 of the 2010 Form 10-K.

MAIN PASS ENERGY HUB TM PROJECT

Our long-term business objectives may include the pursuit of a multifaceted energy services development of the MPEH tm project. Commercialization efforts are ongoing including discussions regarding utilization of the MPEH tm assets for handling and storage of various hydrocarbon commodities. As of June 30, 2011, we have incurred approximately $52.9 million of cumulative cash costs associated with our pursuit of the establishment of MPEH tm , including $0.4 million in the six months ended June 30, 2011. As of June 30, 2011, we have recognized a liability of $12.5 million relating to the future reclamation of the MPEH tm related facilities. The actual amount and timing of the obligation for reclamation of these structures is dependent on the success of our efforts to use these facilities at the MPEH tm project.

We will require commercial arrangements for the MPEH tm project to obtain financing, which may be in the form of additional debt and/or equity transactions. The ultimate outcome of our efforts to enter into commercial arrangements on reasonable terms to develop the MPEH tm project and obtain additional financing is subject to various uncertainties, many of which are beyond our control. Commercialization of the project has been adversely affected by increased domestic supplies of natural gas, excess LNG re-gasification capacity and general market conditions.

For additional information regarding the MPEH tm project, see “Main Pass Energy Hub tm Project” in Part 1, Items 1. and 2. “Business and Properties” in the 2010 Form 10-K.

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NEW ACCOUNTING STANDARDS

We do not expect the adoption of any accounting standards in 2011 to have a material impact to our financial statements.

CAUTIONARY STATEMENT

Management’s Discussion and Analysis of Financial Condition and Results of Operations contain forward-looking statements in which we discuss certain of our expectations regarding future operational and financial performance. Forward-looking statements are all statements other than statements of historical facts, such as those statements regarding potential oil and gas discoveries, projected oil and gas exploration, development and production activities and costs, amounts and timing of capital expenditures, reclamation, indemnification and environmental obligations and costs, potential quarterly and annual production rates, reserve estimates, projected operating cash flows and liquidity, and statements about the potential opportunities and benefits presented by the recent property acquisition, including expectations regarding reserve estimates and production rates. The words “anticipates,” “may,” “can,” “plans,” “believes,” “estimates,” “expects,” “projects,” “intends,” “likely,” “will,” “should,” “to be,” and any similar expressions and/or statements that are not historical facts are intended to identify those assertions as forward-looking statements.

However, we caution readers that forward-looking statements are not guarantees of future performance or exploration and development success, and our actual exploration experience and future financial results may differ materially from those anticipated, projected or assumed in the forward-looking statements. Important factors that may cause our actual results to differ materially from those anticipated by the forward-looking statements include, but are not limited to, those associated with general economic and business conditions, failure to realize expected value creation from property acquisitions, including the recent acquisition of assets from PXP, exercise of preferential rights to purchase, variations in the market demand for, and prices of, oil and natural gas, drilling results, unanticipated fluctuations in flow rates of producing wells due to mechanical or operational issues (including those experienced by wells operated by third parties where we are a participant), oil and natural gas reserve expectations, the potential adoption of new governmental regulations (including any enhanced regulatory oversight attributable to the governmental response to the Deepwater Horizon incident), failure of third party partners to fulfill their commitments, the ability to satisfy future cash obligations and environmental costs, adverse conditions, such as high temperatures and pressure that could lead to mechanical failures or increased costs, the ability to hold current or future lease acreage rights, the ability to satisfy future cash obligations and environmental costs, access to capital to fund drilling activities, as well as other general exploration and development risks and hazards, and other factors described in more detail under “Risk Factors” included in our 2010 Form 10-K, as updated by our subsequent filings with the SEC.

Investors are cautioned that many of the assumptions upon which our forward-looking statements are based are likely to change after our forward-looking statements are made, including for example the market prices of oil and natural gas, which we cannot control, and production volumes and costs, some aspects of which we may or may not be able to control. Further, we may make changes to our business plans that could or will affect our results. We caution investors that we do not intend to update our forward-looking statements more frequently than quarterly, notwithstanding any changes in our assumptions, changes in our business plans, our actual experience, or other changes, and we undertake no obligation to update any forward-looking statements.

–––––––––––––––––––––––––

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

There have been no material changes in our market risks since the year ended December 31, 2010. For additional information on market risks, refer to “Disclosures About Market Risks” included in Part II, Items 7 and 7a of our 2010 Form 10-K.

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Item 4. Controls and Procedures .

(a) Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, with the participation of management, have evaluated the effectiveness of our “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this quarterly report on Form 10-Q. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective as of the end of the period covered by this report.

(b) Changes in internal control. There has been no change in our internal control over financial reporting that occurred during the three months ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings .

We may from time to time be involved in various legal proceedings of a character normally incident to the ordinary course of our business. We believe that potential liability from any of these pending or threatened proceedings will not have a material adverse effect on our financial condition or results of operations. We maintain liability insurance to cover some, but not all, of the potential liabilities normally incident to the ordinary course of our businesses as well as other insurance coverage customary in our business, with coverage limits as we deem prudent at an acceptable cost.

Item 1A. Risk Factors.

Except as otherwise described below, there have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of the 2010 Form 10-K.

Offshore operations are hazardous, and the hazards are not fully insurable at commercially reasonable costs.

Our operations are subject to the hazards and risks inherent in drilling for, producing and transporting oil and natural gas. These hazards and risks include:

•

fires;

•

natural disasters;

•

abnormal pressures in geologic formations;

•

blowouts;

•

cratering;

•

pipeline ruptures; and

•

spills.

If any of these or similar events occur, we could incur substantial losses as a result of death, personal injury, property damage, pollution, lost production, remediation and clean-up costs and other environmental or catastrophic damages.

We have historically maintained insurance for our operations, including liability, property damage, control of well, business interruption (when economically feasible), limited coverage for sudden and accidental environmental damages and other insurance. However, market insurance premium rates for operators in the Gulf of Mexico have increased significantly in recent years following hurricane events and more recently, the Deepwater Horizon incident in April 2010. In addition, coverage limits for certain types of catastrophic events, such as hurricanes, have dropped significantly. The combined effects of higher insurance premiums and reduced coverage led management to reconsider its overall insurance program for these kinds of risks. Following this evaluation, in May 2011, we renewed our annual insurance program with no coverage terms for Named Windstorm perils. This decision increases our exposure to

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casualty loss from windstorms and, if such damage was substantial, could have a material adverse effect on our results of operations and financial condition.

Any insurance that we purchase will not provide protection against all potential liabilities incident to the ordinary conduct of our business. Moreover, any insurance we maintain will be subject to coverage exclusions, limits, deductibles and other conditions. In addition, our insurance will not cover damages caused by war or environmental damages that occur over time. The occurrence of a material casualty loss that is not covered by insurance would adversely affect our results of operations and financial condition.

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

(c) The following table sets forth information with respect to shares of our common stock purchased by us during the three months ended June 30, 2011:

Period	(a) Total Number of Shares Purchased	(b) Average Price Paid Per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs a

April 1-30, 2011	-	$ -	-	300,000
May 1-31, 2011	-	-	-	300,000
June 1-30, 2011	-	-	-	300,000

Total	-	$ -	-	300,000

a.	Our Board of Directors has approved an open market share purchase program for up to 2.5 million shares. The program does not have an expiration date. No shares were purchased during the three months ended June 30, 2011 and 0.3 million shares remain available for purchase.

Item 6. Exhibits .

The exhibits to this report are listed in the Exhibit Index appearing on page E-1 hereof.

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McMoRan Exploration Co.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	McMoRan Exploration Co.

	By: /s/ Nancy D. Parmelee
	Nancy D. Parmelee
	Senior Vice President, Chief Financial Officer
	and Secretary
	(authorized signatory and Principal
	Financial Officer)



Date: August 5, 2011

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McMoRan Exploration Co.

Exhibit Index

		Filed
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-Q	Form	File No.	Date Filed
3.1	Composite Certificate of Incorporation of McMoRan		8-A/A	001-07791	01/28/2011
3.2	Certificate of Amendment to the Amended and Restated Certificate of Incorporation of McMoRan		8-K	001-07791	06/17/2011
3.3	Amended and Restated By-Laws of McMoRan as amended effective February 1, 2010		8-K	001-07791	02/03/2010
10.1	Credit Agreement between McMoRan, as parent, McMoRan Oil & Gas LLC, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, Toronto Dominion (Texas) LLC, as syndication agent, BNP Paribas, as documentation agent and the lenders party thereto, dated as of June 30, 2011		8-K	001-07791	07/06/2011
15.1	Letter dated August 5, 2011 from Ernst & Young LLP regarding unaudited interim financial statements	X
31.1	Certification of Principal Executive Officer pursuant to Rule 13a–14(a)/15d-14(a)	X
31.2	Certification of Principal Financial Officer pursuant to Rule 13a–14(a)/15d-14(a)	X
32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350	X
32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350	X
101.INS	XBRL Instance Document	X
101.SCH	XBRL Taxonomy Extension Schema.	X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.	X
101.DEF	XBRL Taxonomy Extension Definition Linkbase.	X
101.LAB	XBRL Taxonomy Extension Label Linkbase.	X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.	X