- 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 September 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 S		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 October 31, 2011, there were issued and outstanding 161,326,556 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 Condensed Consolidated Financial Statements (Unaudited)	7

Report of Independent Registered Public Accounting Firm	23

Item 2. Management's Discussion and Analysis
of Financial Condition and Results of Operations	24

Item 3. Quantitative and Qualitative Disclosures about Market Risk	34

Item 4. Controls and Procedures	35

Part II. Other Information

Item 1. Legal Proceedings	35

Item 1A. Risk Factors	35

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	35

Item 6. Exhibits	35

Signature	36

Exhibit Index	E-1

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Part I. FINANCIAL INFORMATION

Item 1. Financial Statements.

McMoRan EXPLORATION CO.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited )

	September 30,		December 31,
	2011		2010
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	642,273	$	905,684
Accounts receivable		109,428		86,516
Inventories		33,067		38,461
Prepaid expenses		12,835		15,478
Current assets from discontinued operations, including restricted cash
of $473		473		702
Total current assets		798,076		1,046,841
Property, plant and equipment, net		2,021,198		1,785,607
Restricted cash		60,252		53,975
Deferred financing costs and other assets		8,863		9,952
Long-term assets from discontinued operations		2,989		2,989
Total assets	$	2,891,378	$	2,899,364

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	116,397	$	102,658
Accrued liabilities		162,897		99,363
Accrued interest and dividends payable		22,448		6,768
Current portion of accrued oil and gas reclamation costs		103,949		120,970
5¼% convertible senior notes		6,543		74,720
Current portion of accrued sulphur reclamation costs (discontinued operations)		5,577		11,772
Current liabilities from discontinued operations		1,545		1,993
Total current liabilities		419,356		418,244
5¼% convertible senior notes		68,177		-
11.875% senior notes		300,000		300,000
4% convertible senior notes		186,836		185,256
Accrued oil and gas reclamation costs		193,384		237,654
Other long-term liabilities		16,060		16,596
Accrued sulphur reclamation costs (discontinued operations)		14,282		13,494
Other long-term liabilities from discontinued operations		4,325		3,783
Total liabilities		1,202,420		1,175,027
Stockholders' equity		1,688,958		1,724,337
Total liabilities and stockholders' equity	$	2,891,378	$	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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In Thousands, Except Per Share Amounts)
Revenues:
Oil and natural gas	$	134,548		$	90,778		$	423,729		$	323,727
Service		3,635			4,062			9,766			11,642
Total revenues		138,183			94,840			433,495			335,369
Costs and expenses:
Production and delivery costs		61,182			47,071			161,050			136,295
Depletion, depreciation and amortization expense		66,730			48,588			248,738			214,720
Exploration expenses		18,158			5,256			78,832			28,099
Gain on oil and gas derivative contracts		-			(942	)		-			(4,210	)
General and administrative expenses		11,877			11,148			39,052			35,267
Main Pass Energy Hub ™ costs		49			230			562			805
Insurance recoveries		(22,649	)		(5,584	)		(52,018	)		(14,755	)
Gain on sale of oil and gas property		-			-			(900	)		(3,455	)
Total costs and expenses		135,347			105,767			475,316			392,766
Operating income (loss)		2,836			(10,927	)		(41,821	)		(57,397	)
Interest expense, net		(629	)		(8,690	)		(8,782	)		(29,096	)
Other income, net		204			72			614			177
Income (loss) from continuing operations before income taxes		2,411			(19,545	)		(49,989	)		(86,316	)
Income tax expense		-			-			-			-
Income (loss) from continuing operations		2,411			(19,545	)		(49,989	)		(86,316	)
Loss from discontinued operations		(1,489	)		(1,184	)		(4,722	)		(4,260	)
Net income (loss)		922			(20,729	)		(54,711	)		(90,576	)
Preferred dividends and inducement payments for early
conversion of convertible preferred stock		(10,342	)		(4,524	)		(32,457	)		(22,583	)
Net loss applicable to common stock	$	(9,420	)	$	(25,253	)	$	(87,168	)	$	(113,159	)

Basic and diluted net loss per share of common
stock:
Continuing operations		$(0.05	)		$(0.25	)		$(0.52	)		$(1.17	)
Discontinued operations		(0.01	)		(0.01	)		(0.03	)		(0.05	)
Net loss per share of common stock		$(0.06	)		$(0.26	)		$(0.55	)		$(1.22	)

Average common shares outstanding:
Basic and diluted		159,195			95,469			158,505			92,789

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 )

	Nine Months Ended
	September 30,
	2011			2010
	(In Thousands)
Cash flow from operating activities:
Net loss	$	(54,711	)	$	(90,576	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss from discontinued operations		4,722			4,260
Depletion, depreciation and amortization expense		248,738			214,720
Exploration drilling and related expenditures, net		42,046			7,522
Compensation expense associated with stock-based awards		15,618			15,701
Amortization of deferred financing costs		4,212			2,796
Change in fair value of oil and gas derivative contracts		-			4,065
Reclamation expenditures, net of prepayments by third parties		(93,411	)		(70,786	)
Increase in restricted cash		(3,760	)		(11,041	)
Gain on sale of oil and gas property		(900	)		(3,455	)
Other		(50	)		295
(Increase) decrease in working capital:
Accounts receivable		(47,648	)		16,340
Accounts payable and accrued liabilities		68,058			30,929
Prepaid expenses and inventories		7,056			(459	)
Net cash provided by continuing operations		189,970			120,311
Net cash used in discontinued operations		(11,457	)		(606	)
Net cash provided by operating activities		178,513			119,705

Cash flow from investing activities:
Exploration, development and other capital expenditures		(403,889	)		(160,259	)
Acquisition of oil and gas properties		(10,000	)		-
Proceeds from sale of oil and gas properties		900			2,920
Net cash used in continuing operations		(412,989	)		(157,339	)
Net cash from discontinued operations		-			-
Net cash used in investing activities		(412,989	)		(157,339	)

Cash flow from financing activities :
Dividends paid and inducement payments on early conversion of convertible preferred stock		(27,609	)		(23,136	)
Credit facility refinancing fees		(1,712	)		-
Debt and equity issuance costs		(543	)		-
Proceeds from exercise of stock options and other		929			(455	)
Net cash used in continuing operations		(28,935	)		(23,591	)
Net cash from discontinued operations		-			-
Net cash used in financing activities		(28,935	)		(23,591	)
Net decrease in cash and cash equivalents		(263,411	)		(61,225	)
Cash and cash equivalents at beginning of year		905,684			241,418
Cash and cash equivalents at end of period	$	642,273		$	180,193

Supplemental non-cash investing & financing activities :
Issuance of 2.8 million shares of common stock and other non-cash purchase price consideration related to property acquisition	$	39,198		$	-

The accompanying notes, which include information regarding noncash transactions, are an integral part of these consolidated financial statements.

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENT OF EQUITY (Unaudited )

Nine Months Ended September 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
Common stock issuance		-			28		35,010			-			-			-			35,038
Stock-based compensation
expense		-			-		15,618			-			-			-			15,618
Preferred stock dividends and
conversion inducement payments		-			-		(32,457	)		-			-			-			(32,457	)
Preferred stock conversions		(8,064	)		11		8,053			-			-			-			-
Preferred stock offering cost adjustments		-			-		275			-			-			-			275
Stock option exercises and other		-			1		927			-			-			(40	)		888
Net loss		-			-		-			(54,711	)		-			-			(54,711	)
Other comprehensive loss		-			-		-			-			(30	)		-			(30	)
Balance as of September 30, 2011	$	713,999		$	1,638	$	2,183,856		$	(1,162,192	)	$	(127	)	$	(48,216	)	$	1,688,958

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

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McMoRan EXPLORATION CO.

NOTES TO CONDENSED 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 nine-month periods ended September 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):

	Third Quarter			Nine Months
	2010			2010
Revenues	$	118,594		$	428,535
Operating loss	$	(1,857	)	$	(42,388	)
Net loss to common shareholders	$	(28,835	)	$	(136,105	)

Average basic and diluted shares outstanding		146,469			143,789
Basic and diluted net loss per share of common stock	$	(0.20	)	$	(0.95	)

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 $9.7 million of non-productive exploratory drilling costs and $18.6 million of asset impairment charges for the nine month period ended September 30, 2010.

On September 8, 2011, McMoRan acquired Whitney Exploration LLC’s (Whitney) 2.97% working interest in Davy Jones and 2% working interest in Blackbeard East. Under the terms of the transaction, McMoRan issued approximately 2.8 million shares of its common stock and paid $10 million in cash to Whitney for these interests relating to drilling projects in process. McMoRan’s common stock price on the closing date was $12.36 per share. The fair value of the interests acquired approximated $49 million. The acquisition of Whitney’s interests had no material impact to McMoRan’s statements of operations on a pro forma basis.

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3. LONG-TERM DEBT

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

	September 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 $13,164 and $14,744		186,836			185,256
Total debt		561,556			559,976
Less current maturities		(6,543	)		(74,720	)
Long-term debt	$	555,013		$	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 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 credit 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 credit facility are substantially the same as McMoRan’s prior revolving credit facility. There were no borrowings outstanding under the credit facility during the quarter ended September 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 that is redetermined semi-annually beginning in November 2011 and each April and October thereafter.

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 September 30, 2011.

Exchange Offer for 5¼ % Convertible Senior Notes

On October 6, 2011, McMoRan completed an offer to exchange up to $74,720,000 aggregate principal amount of its 5¼% Convertible Senior Notes due October 6, 2011 (Existing Notes). Existing Notes in the principal amount of $68,177,000 were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due October 6, 2012 (New Notes). McMoRan repaid $6,543,000 of the remaining principal amount of Existing Notes, which matured in accordance with their terms on October 6, 2011. The terms of the New Notes are substantially identical to the terms of the Existing Notes, except that the New Notes have a maturity date of October 6, 2012. The impact of this exchange transaction, which will be recorded as a modification of debt in the fourth quarter of 2011, will result in the recognition of an approximate $2.6 million debt discount related to the fair value of the instruments’ embedded conversion option that will be accreted as a component of interest expense over the one year term of the New Notes.

As of September 30, 2011, $68.2 million of Existing Notes were classified as long-term obligations that will be reclassified to current portion of long-term debt (representing the principal amount of the New Notes) in the fourth quarter of 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 September 30, 2011 and December 31, 2010 (in thousands):

	September 30,		December 31,
	2011		2010
5¼% convertible senior notes	$	74,720	$	89,335
11.875% senior notes		312,000		331,500
4% convertible senior notes		193,100		255,000

Interest Expense, Net

Interest expense, which includes the amortization of deferred financing costs and periodic credit facility fees, is reflected net of amounts capitalized to McMoRan’s in-progress drilling projects. Interest expense capitalized by McMoRan totaled $12.7 million in the third quarter of 2011 and $33.2 million for the nine months ended September 30, 2011. Capitalized interest totaled $3.1 million in the third quarter of 2010 and $6.3 million for the nine months ended September 30, 2010.

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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.

McMoRan had a net loss from continuing operations (net of preferred dividends and inducement payments) in both the third-quarter and nine-month periods ended September 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):

	Third Quarter				Nine Months
	2011		2010		2011		2010
Stock options a		1,338		1,337		1,478		1,262
Shares issuable upon assumed
conversion of:
5.75% preferred stock b		43,750		-		43,750		-
8% preferred stock b		2,046		3,247		2,219		4,800
6¾% preferred stock b		-		10,681		-		10,681
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 nine months ended September 30, 2011, McMoRan induced conversion of approximately 8,100 shares, of its 8% preferred stock and during the third quarter and nine months ended 2010, McMoRan induced conversion of approximately 7,000 shares and 64,200 shares of its 8% preferred stock, respectively (Note 9). Preferred stock dividends and inducement payments for the early conversion of shares of McMoRan’s 8% preferred stock totaled $10.3 million and $32.4 million for the three and nine-month periods ended September 30, 2011, respectively and $4.5 million and $22.6 million for the three and nine-month periods ended September 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 $0.1 million and $0.8 million during the third quarters of 2011 and 2010, respectively and $0.7 million and $2.7 million for the nine-month periods ended September 30, 2011 and 2010, respectively. Interest expense, net on the 4% notes totaled $0.1 million and $1.6 million, respectively, during the third quarter and nine months ended September 30, 2011. Additional information regarding McMoRan’s 4% notes and 5¼% notes is disclosed in Note 6 of the 2010 Form 10-K.

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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:

	Third Quarter				Nine Months
	2011		2010		2011		2010
Outstanding options (in thousands)		8,574		7,814		5,327		7,821
Average exercise price	$	16.88	$	16.52	$	17.78	$	16.52

5. STOCK-BASED COMPENSATION

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

	Third Quarter				Nine Months
	2011		2010		2011		2010
Stock options awarded to employees (including directors)	$	2,542	$	2,757	$	14,659	$	14,704
Stock options awarded to non-employees		136		180		642		690
Restricted stock units		124		107		317		307
Total stock-based compensation cost	$	2,802	$	3,044	$	15,618	$	15,701

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

	Third Quarter				Nine Months
	2011		2010		2011		2010

General and administrative expenses	$	1,588	$	1,629	$	8,460	$	8,153
Exploration expenses		1,194		1,363		7,032		7,282
Main Pass Energy Hub costs		20		52		125		266
Total stock-based compensation cost	$	2,802	$	3,044	$	15,618	$	15,701

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 nine months ended September 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 nine months ended September 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 September 30, 2011, total compensation cost related to nonvested approved stock option awards not yet recognized in earnings was approximately $17.4 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.

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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):

	Third Quarter			Nine Months
	2010			2010
Realized (gain) loss
Gas puts	$	(989	)	$	(989	)
Oil puts		92			92
Gas swaps		-			(8,134	)
Oil swaps		-			756
Total realized gain		(897	)		(8,275	)

Unrealized (gain) loss
Gas puts		583			117
Oil puts		(89	)		(47	)
Gas swaps		(609	)		5,033
Oil swaps		70			(1,038	)
Total unrealized (gain) loss		(45	)		4,065
Gain on oil and gas derivative contracts	$	(942	)	$	(4,210	)

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

7. INCOME TAXES

As of September 30, 2011 and December 31, 2010, McMoRan had approximately $472.1 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 $537.3 million at September 30, 2011. In addition, McMoRan’s allocated costs for the working interests in the properties acquired in the PXP and Whitney property acquisitions associated with the current in-progress and unproven wells totaled $708.8 million at September 30, 2011.

As of September 30, 2011, McMoRan had two wells (the 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 and completion expected by the end of 2011. McMoRan’s total investment in the Davy Jones complex, which includes $483.3 million in allocated property acquisition costs, totaled $699.6 million at September 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.

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. The drilling of this ultra-deep well, which has a proposed total depth of 26,000 feet and is expected to commence in the fourth quarter of 2011, will allow McMoRan to maintain its rights to the 25,000 gross acres within the Blackbeard West unit. 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 September 30, 2011.

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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 $53.4 million at September 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 $11.3 million and $62.0 million, respectively, during the third quarter and nine months ended September 30, 2011 following impairment assessments of the carrying value of its oil and gas properties. The charges incurred during the third quarter 2011 related to declines in market prices for both oil and natural gas from the second quarter 2011 and the impact of increased capitalized costs for certain properties related to asset retirement obligation adjustments. In addition to the third quarter 2011 charges, the majority of the other charges recorded in the nine months ended September 30, 2011 consisted of approximately $23.8 million related to adjustments to proved reserves following the evaluation of drilling results at a proved undeveloped location and 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 $11.3 million and $82.0 million, respectively, primarily due to declines in market prices for natural gas in the first and third quarters of 2010 and negative reserve revisions resulting from well 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 in excess of $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 $116 million. Additional recoveries will be recorded as these costs are funded in the future. McMoRan recognized net insurance recoveries of $22.6 million and $52.0 million, respectively, during the third quarter and nine months ended September 30, 2011 and recognized net insurance

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recoveries of $5.6 million and $14.8 million, respectively, during the third quarter and nine months ended September 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 obligations at December 31, 2010	$	358,624		$	25,266
Liabilities settled		(125,560	)		(9,863	)
Accretion expense		10,726			3,456
Incurred liabilities		-			-
Revisions for changes in estimates		54,596	a		1,000
Other		(1,053	)		-
Asset retirement obligations at September 30, 2011	$	297,333		$	19,859

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 September 30, 2011, McMoRan has incurred over $335 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 $100 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, without limitation, 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, and changes in scope that are identified as reclamation projects progress. McMoRan revises its reclamation estimates, as appropriate, when such changes in estimates become known.

Effects of Deepwater Horizon Incident on Drilling and Other Commitments.

McMoRan has significant drilling and other commitments associated with its business strategy. The April 2010 Deepwater Horizon incident and the industry-wide increase in regulatory and compliance-related issues resulting therefrom have created additional uncertainties, some of which have impacted 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. To partially offset the loss associated with the idle drilling rig, McMoRan negotiated an arrangement with a third party to use the drilling rig on a short-term basis through the third quarter extending into early October 2011. The net costs of the drilling rig in excess of the third party reimbursements were recorded to exploration expense and totaled approximately $3.8 million and $7.6 million, respectively, for the three and nine-month periods ended September 30, 2011. For more information regarding the April 2010 Deepwater Horizon incident and the risks associated with matters that resulted from that incident see Item 1A. “Risk Factors” included in McMoRan’s 2010 Form 10-K.

9. OTHER MATERS

8% Preferred Stock Conversions.

During the nine months ended September 2011, 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 (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock) . McMoRan paid an aggregate of $1.5 million in cash to the holders of these shares during the nine months ended September 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 third quarter ended September 2010, McMoRan privately negotiated the induced conversion of approximately 7,000 shares of its 8% preferred stock with a liquidation preference of $7.0 million into approximately 1.0 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 $1.4 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 third quarter of 2010. McMoRan induced conversion of approximately 64,200 shares of its 8% preferred stock with a liquidation preference of $64.2 million into approximately 9.4 million shares of McMoRan common stock during the nine months ended

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September 30, 2010. McMoRan paid an aggregate of $12.2 million in cash to the holders of these shares during the nine months ended September 30, 2010 to induce the early conversions of these shares.

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 follow (in thousands):

	Third Quarter						Nine Months
	2011			2010			2011			2010
Service cost	$	14		$	17		$	42		$	50
Interest cost		50			60			151			180
Return on plan assets		-			-			-			-
Amortization of prior service costs
and actuarial gains		(10	)		(9	)		(30	)		(27	)
Net periodic benefit expense	$	54		$	68		$	163		$	203

Comprehensive loss.

McMoRan’s comprehensive loss follows (in thousands):

	Third Quarter						Nine Months
	2011			2010			2011			2010
Net loss	$	(9,420	)	$	(25,253	)	$	(87,168	)	$	(113,159	)
Other comprehensive loss:
Amortization of previously unrecognized pension
components, net		(10	)		(9	)		(30	)		(27	)
Comprehensive loss	$	(9,430	)	$	(25,262	)	$	(87,198	)	$	(113,186	)

Subsequent Events Evaluation.

McMoRan evaluated subsequent events for purposes of its September 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 September 30, 2011 and December 31, 2010 and the related condensed consolidating statements of operations and cash flow for the quarter and nine months ended September 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)

September 30, 2011

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	4,661	$	637,028	$	584		$	-		$	642,273
Accounts receivable		-		109,428		-			-			109,428
Inventories		-		33,067		-			-			33,067
Prepaid expenses		833		12,002		-			-			12,835
Current assets from discontinued
operations		-		-		473			-			473
Total current assets		5,494		791,525		1,057			-			798,076
Property, plant and equipment, net		-		2,021,167		31			-			2,021,198
Investment in subsidiaries		1,550,269		-		-			(1,550,269	)		-
Amounts due from affiliates		718,679				-			(718,679	)		-
Restricted cash and other
assets		5,008		64,107		-			-			69,115
Long-term assets from discontinued operations		-		-		2,989			-			2,989
Total assets	$	2,279,450	$	2,876,799	$	4,077		$	(2,268,948	)	$	2,891,378

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities :
Accounts payable	$	469	$	115,362	$	566		$	-		$	116,397
Accrued liabilities		1,139		162,316		(558	)		-			162,897
Current portion of debt		6,543		-		-			-			6,543
Current portion of oil and gas
accrued reclamation costs		-		103,949		-			-			103,949
Other current liabilities		21,686		762		-			-			22,448
Current liabilities from discontinued
operations		-		-		7,122			-			7,122
Total current liabilities		29,837		382,389		7,130			-			419,356
Long-term debt		555,013		-		-			-			555,013
Amounts due to affiliates		-		716,446		2,233			(718,679	)		-
Accrued oil and gas reclamation costs		-		193,384		-			-			193,384
Other long-term liabilities		5,642		8,802		1,616			-			16,060
Long-term liabilities from discontinued
operations		-		-		18,607			-			18,607
Total liabilities		590,492		1,301,021		29,586			(718,679	)		1,202,420
Stockholders’ equity (deficit)		1,688,958		1,575,778		(25,509	)		(1,550,269	)		1,688,958
Total liabilities and stockholders’
equity (deficit)	$	2,279,450	$	2,876,799	$	4,077		$	(2,268,948	)	$	2,891,378

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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 September 30, 2011

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	134,548		$	-		$	-		$	134,548
Service		-			3,635			-			-			3,635
Total revenues		-			138,183			-			-			138,183
Costs and expenses:
Production and delivery costs		-			61,191			(9	)		-			61,182
Depletion, depreciation and amortization
expense		-			66,730			-			-			66,730
Exploration expenses		-			18,158			-			-			18,158
General and administrative expenses		2,228			9,649			-			-			11,877
Main Pass Energy Hub TM costs		-			-			49			-			49
Insurance recoveries		-			(22,649	)		-			-			(22,649	)
Total costs and expenses		2,228			133,079			40			-			135,347
Operating income (loss)		(2,228	)		5,104			(40	)		-			2,836
Interest expense, net		(629	)		-			-			-			(629	)
Equity in losses of consolidated
subsidiaries		3,785			-			-			(3,785	)		-
Other income (expense), net		(6	)		210			-			-			204
Income (loss) from continuing operations before income taxes		922			5,314			(40	)		(3,785	)		2,411
Income tax expense		-			-			-			-			-
Income (loss) from continuing operations		922			5,314			(40	)		(3,785	)		2,411
Loss from discontinued operations		-			-			(1,489	)		-			(1,489	)
Net income (loss)		922			5,314			(1,529	)		(3,785	)		922
Preferred dividends and other related
preferred stock costs		(10,342	)		-			-			-			(10,342	)
Net income (loss) applicable to common stock	$	(9,420	)	$	5,314		$	(1,529	)	$	(3,785	)	$	(9,420	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Nine Months Ended September 30, 2011

							Freeport					Consolidated
	Parent			MOXY			Energy			Eliminations		McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	423,729		$	-		$	-	$	423,729
Service		-			9,766			-			-		9,766
Total revenues		-			433,495			-			-		433,495
Costs and expenses:
Production and delivery costs		-			161,075			(25	)		-		161,050
Depletion, depreciation and amortization
expense		-			248,738			-			-		248,738
Exploration expenses		-			78,832			-			-		78,832
General and administrative expenses		7,520			31,532			-			-		39,052
Main Pass Energy Hub TM costs		-			-			562			-		562
Insurance recoveries		-			(52,018	)		-			-		(52,018	)
Gain on sale of oil and gas property		-			(900	)		-			-		(900	)
Total costs and expenses		7,520			467,259			537			-		475,316
Operating loss		(7,520	)		(33,764	)		(537	)		-		(41,821	)
Interest expense, net		(8,782	)		-			-			-		(8,782	)
Equity in losses of consolidated													-
subsidiaries		(38,393	)		-			-			38,393		-
Other income (expense), net		(16	)		630			-			-		614
Loss from continuing operations before
income taxes		(54,711	)		(33,134	)		(537	)		38,393		(49,989	)
Income tax expense		-			-			-			-		-
Loss from continuing operations		(54,711	)		(33,134	)		(537	)		38,393		(49,989	)
Loss from discontinued operations		-			-			(4,722	)		-		(4,722	)
Net loss		(54,711	)		(33,134	)		(5,259	)		38,393		(54,711	)
Preferred dividends and other related
preferred stock costs		(32,457	)		-			-			-		(32,457	)
Net loss applicable to common stock	$	(87,168	)	$	(33,134	)	$	(5,259	)	$	38,393	$	(87,168	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Three Months Ended September 30, 2010

							Freeport					Consolidated
	Parent			MOXY			Energy			Eliminations		McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	90,778		$	-		$	-	$	90,778
Service		-			4,062			-			-		4,062
Total revenues		-			94,840			-			-		94,840
Costs and expenses:
Production and delivery costs		-			47,085			(14	)		-		47,071
Depletion, depreciation and amortization
expense		-			48,588			-			-		48,588
Exploration expenses		-			5,256			-			-		5,256
Gain on oil and gas derivative contracts		-			(942	)		-			-		(942	)
General and administrative expenses		2,654			8,494			-			-		11,148
Main Pass Energy Hub TM costs		-			-			230			-		230
Insurance recoveries		-			(5,584	)		-			-		(5,584	)
Gain on sale of oil and gas property		-			-			-			-		-
Total costs and expenses		2,654			102,897			216			-		105,767
Operating loss		(2,654	)		(8,057	)		(216	)		-		(10,927	)
Interest expense, net		(8,670	)		(20	)		-			-		(8,690	)
Equity in losses of consolidated													-
subsidiaries		(9,399	)		-			-			9,399		-
Other income (expense), net		(6	)		78			-			-		72
Loss from continuing operations before
income taxes		(20,729	)		(7,999	)		(216	)		9,399		(19,545	)
Income tax expense		-			-			-			-		-
Loss from continuing operations		(20,729	)		(7,999	)		(216	)		9,399		(19,545	)
Loss from discontinued operations		-			-			(1,184	)		-		(1,184	)
Net loss		(20,729	)		(7,999	)		(1,400	)		9,399		(20,729	)
Preferred dividends and other related
preferred stock costs		(4,524	)		-			-			-		(4,524	)
Net loss applicable to common stock	$	(25,253	)	$	(7,999	)	$	(1,400	)	$	9,399	$	(25,253	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Nine Months Ended September 30, 2010

							Freeport					Consolidated
	Parent			MOXY			Energy			Eliminations		McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	323,727		$	-		$	-	$	323,727
Service		-			11,642			-			-		11,642
Total revenues		-			335,369			-			-		335,369
Costs and expenses:
Production and delivery costs		-			136,334			(39	)		-		136,295
Depletion, depreciation and amortization
expense		-			214,720			-			-		214,720
Exploration expenses		-			28,099			-			-		28,099
Gain on oil and gas derivative contracts		-			(4,210	)		-			-		(4,210	)
General and administrative expenses		5,565			29,702			-			-		35,267
Main Pass Energy Hub TM costs		-			-			805			-		805
Insurance recoveries		-			(14,755	)		-			-		(14,755	)
Gain on sale of oil and gas property		-			(3,455	)		-			-		(3,455	)
Total costs and expenses		5,565			386,435			766			-		392,766
Operating loss		(5,565	)		(51,066	)		(766	)		-		(57,397	)
Interest expense, net		(29,076	)		(20	)		-			-		(29,096	)
Equity in losses of consolidated													-
subsidiaries		(55,928	)		-			-			55,928		-
Other income (expense), net		(7	)		184			-			-		177
Loss from continuing operations before
income taxes		(90,576	)		(50,902	)		(766	)		55,928		(86,316	)
Income tax expense		-			-			-			-		-
Loss from continuing operations		(90,576	)		(50,902	)		(766	)		55,928		(86,316	)
Loss from discontinued operations		-			-			(4,260	)		-		(4,260	)
Net loss		(90,576	)		(50,902	)		(5,026	)		55,928		(90,576	)
Preferred dividends and other related
preferred stock costs		(22,583	)		-			-			-		(22,583	)
Net loss applicable to common stock	$	(113,159	)	$	(50,902	)	$	(5,026	)	$	55,928	$	(113,159	)

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW (UNAUDITED)

Nine Months Ended September 30, 2011

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)

Cash flow from operating activities:
Net cash provided by (used in) continuing
operations	$	(10,359	)	$	200,767		$	(438	)	$	189,970
Net cash used in discontinued operations		-			-			(11,457	)		(11,457	)
Net cash provided by (used in) operating
activities		(10,359	)		200,767			(11,895	)		178,513

Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(403,889	)		-			(403,889	)
Acquisition of oil and gas properties		-			(10,000	)		-			(10,000	)
Proceeds from sale of oil and gas property		-			900			-			900
Net cash used in investing activities		-			(412,989	)		-			(412,989	)

Cash flow from financing activities:
Dividends paid and conversion inducement		(27,609	)		-			-			(27,609	)
payments on convertible preferred stock
Credit facility refinancing		-			(1,712	)		-			(1,712	)
Proceeds from exercise of stock options		929			-			-			929
Debt and equity issuance costs		(543	)		-			-			(543	)
Investment from parent		(12,000	)		-			12,000			-
Amounts payable to consolidated affiliate		53,823			(53,927	)		104			-
Net cash (used in) provided by financing
activities		14,600			(55,639	)		12,104			(28,935	)

Net increase (decrease) in cash and cash		4,241			(267,861	)		209			(263,411	)
equivalents
Cash and cash equivalents at beginning		420			904,889			375			905,684
of year
Cash and cash equivalents at end of period	$	4,661		$	637,028		$	584		$	642,273

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW (UNAUDITED)

Nine Months Ended September 30, 2010

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)

Cash flow from operating activities:
Net cash provided by (used in) continuing
operations	$	27,970		$	94,917		$	(2,576	)	$	120,311
Net cash used in discontinued operations		-			-			(606	)		(606	)
Net cash provided by (used in) operating
activities		27,970			94,917			(3,182	)		119,705

Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(160,259	)		-			(160,259	)
Proceeds from sale of oil and gas property		-			2,920			-			2,920
Net cash used in investing activities		-			(157,339	)		-			(157,339	)

Cash flow from financing activities:
Dividends paid and conversion inducement		(23,136	)		-			-			(23,136	)
payments on convertible preferred stock
Proceeds from exercise of stock options and other		(455	)		-			-			(455	)
Investment from parent		(3,350	)		-			3,350			-
Net cash (used in) provided by financing
activities		(26,941	)		-			3,350			(23,591	)

Net increase (decrease) in cash and cash
equivalents		1,029			(62,422	)		168			(61,225	)
Cash and cash equivalents at beginning
of year		16			241,400			2			241,418
Cash and cash equivalents at end of year	$	1,045		$	178,978		$	170		$	180,193

11. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan sustained losses from continuing operations totaling $50.0 million for the nine months ended September 30, 2011, which were inadequate to cover its fixed charges of $42.3 million for the nine months ended September 30, 2011. McMoRan sustained losses from continuing operations totaling $86.3 million for the nine months ended September 30, 2010, which were inadequate to cover its fixed charges of $35.6 million for the nine months ended September 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 September 30, 2011, and the related consolidated statements of operations for the three and nine-month periods ended September 30, 2011 and 2010 and cash flow for the nine month periods ended September 30, 2011 and 2010, and the consolidated statement of equity for the nine month period ended September 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

November 9, 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 820,000 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 our 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.

On September 8, 2011, we acquired Whitney Exploration LLC’s (Whitney) 2.97% working interest in Davy Jones and 2% working interest in Blackbeard East. Under the terms of the transaction, we issued approximately 2.8 million shares of our common stock and paid $10 million in cash to Whitney for these interests relating to drilling projects in progress. Our common stock price on the closing date was $12.36 per share. The fair value of the interests we acquired approximated $49 million.

During the nine months ended September 30, 2011, we invested $403.9 million on capital-related projects primarily associated with our exploration activities. We expect 2011 capital expenditures to approximate $500-550 million, including $300-350 million for exploration and $200 million for development. During the nine months ended September 30, 2011, we also incurred $93.4 million of net abandonment expenditures. We plan to spend approximately $140 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.

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,

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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 third quarter revenues were derived 51 percent from oil and 49 percent from natural gas. North American natural gas averaged $4.06 per MMbtu during the third quarter of 2011. The spot price for natural gas was $3.70 per MMbtu on November 7, 2011. The average oil price for the third quarter of 2011 was $89.59 per barrel, and the spot price for oil was $95.52 per barrel on November 7, 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 our 2010 Form 10-K).

OPERATIONAL ACTIVITIES

Production Update

Third-quarter 2011 production averaged 187 MMcfe/d net to us, compared with 146 MMcfe/d in the third quarter of 2010. Production in the third quarter of 2011 was higher than previously reported estimates of 180 MMcfe/d in July 2011 because of favorable production performance. Production is expected to average approximately 170 MMcfe/d in the fourth quarter of 2011 and 187 MMcfe/d for the year. 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 163 MMcfe/d (67 MMcfe/d net to us) in the third quarter of 2011, compared with 182 MMcfe/d (34 MMcfe/d net to us) in the third quarter of 2010. The higher percentage of net production owned by us in 2011 compared to 2010 represents the impact of our additional interest acquired in the PXP Acquisition. We own a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

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 (GOM) below the salt weld (i.e. listric fault) at depths generally below 25,000 feet. The data gained to date from five 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 GOM.

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Our activities to date have confirmed that drilling below the salt weld on the Shelf of the GOM 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 GOM and in international locations. We intend to conduct further drilling and flow testing to determine the ultimate potential of this emerging geologic trend.

Davy Jones

In September 2011, we commenced installation of production facilities on South Marsh Island Block 230 for the Davy Jones field. We have mobilized a drilling rig and have commenced completion activities for the development of Wilcox sands in the Davy Jones discovery well (Davy Jones No.1), with flow testing expected by year-end 2011.

As previously reported, we have drilled two successful sub-salt wells in the Davy Jones field. The Davy Jones No.1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. The Davy Jones offset appraisal well (Davy Jones No. 2), which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect, and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. We have advanced the technology, equipment and processes needed to develop this field and expect to complete and flow test Davy Jones No. 1 by year-end 2011 and Davy Jones No. 2 in the second half of 2012. Following successful flow tests, we expect production from both wells to utilize new production facilities currently being installed.

Davy Jones involves a large ultra-deep structure encompassing four OCS lease blocks 20,000 acres. We hold a 63.4 percent working interest and a 50.2 percent net revenue interest in Davy Jones. Our total investment in Davy Jones, which includes $483.3 million in allocated property acquisition costs, totaled $699.6 million at September 30, 2011.

Blackbeard East

We commenced drilling the Blackbeard East ultra-deep exploration by-pass well on August 25, 2011 at 30,630 feet. The by-pass well is currently drilling below 32,300 feet to evaluate Eocene objectives encountered in the original well prior to a mechanical issue. The original well was drilled to 32,559 feet. The by-pass well is permitted to 34,000 feet.

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. The well previously encountered 178 net feet of hydrocarbons in the Miocene sands above 25,000 feet. 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 72.0 percent working interest and a 57.4 percent net revenue interest in the well. Our total investment in Blackbeard East, which includes $130.4 million in allocated property acquisition costs, totaled $252.4 million at September 30, 2011.

Lafitte

The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, commenced drilling on October 3, 2010. Wireline logs from interim logging operations in September 2011 and recent logging operations in October 2011 indicate several Lower Miocene sands that appear to be hydrocarbon bearing. The sands have various thicknesses that aggregate approximately 250 gross feet (115 feet net), some of which are contained within a thin-bedded, sand-shale formation. These Lower Miocene aged sands are correlative to Lower Miocene sands seen onshore and in the deepwater of the GOM and provide additional confirmation of our ultra-deep geologic model. Lafitte is our third ultra-deep prospect to encounter Miocene age sands below the salt weld on the GOM Shelf.

The Lafitte well is drilling below 29,500 feet with a proposed total depth of 29,950 feet to evaluate deeper Miocene objectives and possibly the Oligocene section. We hold a 72.0 percent working interest and a 58.3 percent net revenue interest in Lafitte. Our total investment in Lafitte, which includes $35.9 million in allocated property acquisition costs, totaled $130.5 million at September 30, 2011.

Blackbeard West Unit

The Blackbeard West ultra-deep exploratory well on South Timbalier Block 168 (Blackbeard West #1 well) 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. Our total investment in the Blackbeard West #1 well, which includes $27.6 million in allocated costs associated with the PXP Acquisition, totaled $58.9 million at September 30, 2011.

We plan to commence drilling an ultra-deep well within the Blackbeard West unit on Ship Shoal Block 188 in the fourth quarter of 2011. The well has a proposed total depth of 26,000 feet and is located approximately 4 miles west of the Blackbeard West #1 well. We hold a 67.3 percent working interest and a 51.5 percent net revenue interest in the Ship Shoal

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Block 188 well.

Shallow Water Deep Gas Exploration and Development Activities. In addition to the ultra-deep play on the Shelf of the GOM, 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.

Boudin

The Boudin deep gas exploration well, which is located in 20 feet of water on Eugene Island Block 26, commenced drilling on February 27, 2011. The well was drilled to a total depth of 24,284 feet. Drilling results indicate potential hydrocarbon bearing zones within a laminated sand section in the Rob-L. The well has been temporarily abandoned while completion alternatives are evaluated. 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 property acquisition costs, totaled $51.3 million at September 30, 2011.

Acreage Position

As of September 30, 2011, we owned or controlled interests in 426 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 0.82 million gross acres (0.51 million acres net to our interests). Our acreage position includes 0.71 million gross acres (0.44 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 acres of our net leasehold interests are scheduled to expire in the remainder of 2011. 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.

Effects of Deepwater Horizon Incident on Drilling and Other Commitments

We have significant drilling and other commitments associated with our business strategy. The April 2010 Deepwater Horizon incident and the industry-wide increase in regulatory and compliance related issues resulting therefrom have created additional uncertainties, some of which have impacted drilling schedules and presented challenges in managing ongoing rig commitments. We incurred idle rig costs of approximately $3.8 million during the second quarter of 2011. To partially offset the idle drilling rig costs, we negotiated an arrangement with a third party to use the drilling rig on a short-term basis through the third quarter extending into early October 2011. The net costs of the drilling rig in excess of the third party reimbursements were recorded to exploration expense and totaled approximately $3.8 million and $7.6 million, respectively, for the three and nine-month periods ended September 30, 2011. For more information regarding the April 2010 Deepwater Horizon incident and the risks associated with matters that resulted from that incident see Item 1A. “Risk Factors” included in our 2010 Form 10-K.

RESULTS OF OPERATIONS

Our third quarter 2011 operating income of $2.8 million reflects (a) impairment charges of $11.3 million for certain fields to reduce their net carrying value to fair value; (b) adjustments totaling approximately $10.4 million charged against earnings for increases in asset retirement obligations associated with certain of our oil and gas properties; (c) $24.9 million in workover expenses; (d) a gain of $22.6 million for net insurance recoveries associated with insured hurricane-related losses; (e) $2.8 million in charges related to stock-based compensation expense; and (f) $3.1 million in charges to exploration expense for non-productive well costs and unproven leasehold cost reductions.

Our operating loss of $41.8 million for the first nine months ended September 30, 2011 reflects (a) impairment charges of $62.0 million for certain fields to reduce their net carrying value to fair value; (b) adjustments totaling approximately $46.0 million charged against earnings for asset retirement obligations associated with certain of our oil and gas properties, approximately $18.7 million of which was covered for reimbursement under our insurance program; (c) $42.3 million in workover expenses; (d) a gain of $52.0 million for net insurance recoveries associated with insured hurricane-related losses; (e) $15.6 million in charges related to stock-based compensation expense; and (f) $42.0 million in charges to exploration expense related to the Blueberry Hill unproductive well costs and certain unproven leasehold cost reductions.

Our third quarter 2010 operating loss of $10.9 million reflects impairment charges of $11.3 million for certain fields to reduce their net carrying value to fair value which were partially offset by (a) a $5.6 million gain associated with our share of a partial payment for insured losses related to the September 2008 hurricanes; and (b) $0.9 million of net gains on oil and gas derivative contracts (Note 6).

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Our operating loss of $57.4 million for the nine months ended September 30, 2010 reflects (a) impairment charges of $82.0 million for certain fields to reduce their net carrying value to fair value; and (b) $7.5 million in charges to exploration expense primarily related to the Blueberry Hill appraisal well. These charges are offset by (i) a $14.8 million gain associated with our share of a partial payment for insured losses related to the September 2008 hurricanes; (ii) $4.2 million of net gains on oil and gas derivative contracts (Note 6); and (iii) a $3.5 million gain on the sale of an oil and gas property.

Summarized operating data are as follows:

	Third Quarter		Nine Months
	2011	2010	2011	2010
Sales volumes:
Gas (thousand cubic feet, or Mcf)	11,367,900	8,754,300	34,638,000	29,795,900
Oil (barrels)	674,700	534,000	2,139,800	1,851,900
Plant products (per Mcf equivalent) a	1,756,400	1,484,700	5,137,700	4,681,300
Average realizations b
Gas (per Mcf)	$ 4.38	$ 4.61	$ 4.54	$ 4.97
Oil (per barrel)	100.94	75.78	102.56	76.13

Results include approximately $16.5 million and $46.3 million of revenues associated with plant products (ethane, propane, butane, etc.) during the third quarter and nine months ended September 30, 2011, respectively. Plant product revenues for the comparable prior year periods totaled $9.8 million and $34.3 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.

Oil and Gas Operations

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

	Third				Nine
	Quarter				Months
Oil and natural gas revenues – prior year period	$	90,778		$	323,727
Increase (decrease)
Price realizations:
Natural gas		(2,615	)		(14,894	)
Oil and condensate		16,975			56,555
Sales volumes:
Natural gas		12,048			24,066
Oil and condensate		10,662			21,918
Plant products revenues		6,679			11,940
Other		21			417
Oil and natural gas revenues – current year period	$	134,548		$	423,729

Our oil and natural gas sales volumes totaled 17.2 billion cubic feet of natural gas equivalent (Bcfe) in the third quarter of 2011, a 28 percent increase from the 13.4 Bcfe of sales volume generated in the third quarter of 2010. This increase was primarily related to additional volumes received from producing properties acquired during the PXP Acquisition as well as additional volumes received from our Laphroaig No. 2 well that commenced production during the second quarter 2011. Average realizations received for oil and natural gas sold during the third quarter of 2011 increased 33 percent for oil and decreased five 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 $16.5 million in the third quarter of 2011 compared with $9.8 million in the prior year period. This increase was primarily due to our increased ownership in the Flatrock property as a result of the PXP Acquisition. Our service revenues totaled $3.6 million in the third quarter of 2011 and $4.1 million in the same period for 2010. The decrease was due a decrease in production fees related to declining production at certain of our maturing properties.

Our oil and natural gas sales volumes totaled 52.6 Bcfe and 45.6 Bcfe in the nine months ended September 30, 2011 and 2010, respectively. This increase was primarily related to additional volumes received from producing properties acquired during the PXP Acquisition as well as additional volumes received from our Laphroaig No. 2 well that commenced production during the second quarter 2011. Average realizations received for oil and natural gas sold during the nine months ended September 30, 2011 increased 35 percent for oil and decreased nine percent for natural gas compared to amounts received in 2010 (see “—North American Natural Gas and Oil Market Environment”

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above). Revenues from plant products totaled $46.3 million in the nine months ended September 30, 2011 compared with $34.3 million in the prior year period. This increase was primarily due to our increased ownership in the Flatrock property as a result of the PXP Acquisition. Our service revenues totaled $9.8 million in the nine months ended September 30, 2011 and $11.6 million in the same period for 2010. The decrease was due a decrease in production fees related to declining production at certain of our maturing properties.

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

	Third Quarter						Nine Months
		Per			Per			Per		Per
	2011	Mcfe	2010		Mcfe		2011	Mcfe	2010	Mcfe
Lease operating expense	$27.1	$1.58	$25.2		$1.87		$85.4	$1.62	$78.9	$1.73
Workover costs	24.9	1.45	9.6		0.71		42.3	0.80	17.3	0.38
Hurricane related expenses	-	-	1.2		0.09		0.1	0.00	3.9	0.09
Insurance	1.6	0.09	6.5		0.48		12.7	0.24	19.7	0.43
Transportation and production taxes	6.9	0.40	4.8		0.36		19.3	0.37	16.5	0.36
Other	0.7	0.04	(0.2	)	(0.01	)	1.3	0.03	-	-
Total production and delivery costs	$61.2	$3.56	$47.1		$3.50		$161.1	$3.06	$136.3	$2.99

Lease operating expense (LOE) increased approximately $1.9 million and $6.5 million, respectively, in the third quarter and nine months ended September 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 4.5 Bcfe of production in the third quarter of 2011 and $9.3 million of LOE on 14.0 Bcfe of production in the first nine months of 2011). The assets acquired in the PXP Acquisition generated approximately 26% and 27% of our total production volumes in the third quarter and nine months ended September 30, 2011, respectively. Workover costs increased approximately $15.3 million and $25.0 million in the third quarter and nine months ended September 30, 2011, respectively compared to the 2010 periods. The majority of the increase was due to an unproductive workover drilling project totaling approximately $15.3 million during the third quarter 2011 and costs associated with certain regulatory related compliance repairs incurred at our Main Pass 299 facility during the nine months ended September 30, 2011. Transportation, production taxes, and plant product fees increased by approximately $2.1 million in the third quarter of 2011 compared to the 2010 period and $3.8 million in the first nine 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 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 mid-year 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 September 30, 2011.

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

	Third Quarter				Nine Months
		Per		Per		Per		Per
	2011	Mcfe	2010	Mcfe	2011	Mcfe	2010	Mcfe
Depletion and depreciation expense	$41.4	$2.41	$30.7	$2.28	$130.0	$2.47	$117.1	$2.57
Accretion expense	14.0	0.82	6.6	0.49	56.7	1.08	15.6	0.34
Impairment charges/losses	11.3	0.66	11.3	0.84	62.0	1.18	82.0	1.80
Total	$66.7	$3.89	$48.6	$3.61	$248.7	$4.73	$214.7	$4.71

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 depletion and depreciation expense in the third quarter and nine months ended September 30, 2011 compared to the 2010 periods

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is primarily related to higher sales volumes in the third quarter and nine months ended September 30, 2011, respectively.

The increase in accretion expense in the third quarter and nine months ended September 30, 2011 compared to the 2010 periods primarily resulted from approximately $10.4 million (third quarter) and $46.0 million (year to date) of increases to oil and gas property asset retirement obligations, including an adjustment of $18.7 million which is expected to be reimbursed under our insurance program when the related reclamation expenditures are incurred.

Since 2007 and through September 30, 2011, we have incurred over $335 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 $100 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, without limitation, 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, and changes in scope that are identified as reclamation projects progress. We revise our reclamation estimates, as appropriate, when such changes in estimates become known.

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 $11.3 million during the third quarter of 2011. The charges incurred during the third quarter of 2011 related to declines in market prices for both oil and natural gas from the second quarter 2011 and the impact of increased capitalized costs for certain properties from asset retirement obligation adjustments. We recorded impairment charges of $62.0 million during the first nine months of 2011, which in addition to the third-quarter 2011 charges, consisted of approximately $23.8 million related to adjustments to proved reserves following the evaluation of drilling results at a proved undeveloped location and 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. 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 $11.3 million and $82.0 million, respectively, in the third quarter and nine months ended September 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):

	Third Quarter					Nine Months
	2011			2010		2011			2010
Geological and geophysical
including 3-D seismic purchases a	$	6.4		$	4.9	$	17.2		$	13.9
Non-productive exploratory costs, including
related lease costs		3.1	b		0.1		42.0	b		7.5	c
Other d		8.7			0.3		19.6			6.7
	$	18.2		$	5.3	$	78.8		$	28.1

Includes compensation costs associated with outstanding stock-based awards totaling $1.2 million in the third quarter of 2011 and $7.0 million in the nine months ended September 30, 2011 compared with $1.4 million and $7.3 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 non-commercial during the second quarter of 2011 as well as unproven leasehold cost reductions of $2.2 million during the third 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.

d.	Includes $3.6 million and $7.9 million in drilling related insurance costs for the third quarter and nine months

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ended September 30, 2011, respectively. Includes $3.8 million and $7.6 million of drilling rig charges in the third quarter and nine months ended September 30, 2011, respectively. Includes $4.4 million in drilling related insurance costs for the nine months ended September 30, 2010.

Other Financial Results

Operating.

General and administrative expense totaled $11.9 million in the third quarter of 2011 and $39.1 million for the nine months ended September 30, 2011 compared with $11.1 million in the third quarter of 2010 and $35.3 million for the nine months ended September 30, 2010. The increase in these costs for the nine month comparative periods is primarily related to $1.0 million in higher incentive compensation costs during 2011, $1.8 million in higher franchise taxes resulting from our increased stockholders’ equity position related to the equity issued in the PXP Acquisition, approximately $1.0 million of higher information technology related costs for certain system enhancement activities, and $0.7 million in higher legal costs, approximately $0.5 million of which was related to the settlement of a litigation contingency matter.

In the third quarter and nine months ended September 30, 2010, we recorded $0.9 million and $4.2 million in net 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 in excess of $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 $116 million. Additional recoveries will be recorded as these costs are funded in the future. We recorded insurance recoveries of $22.6 million and $52.0 million in the third quarter and nine months ended September 30, 2011, respectively. We received net insurance proceeds of $5.6 million and $14.8 million in the third quarter and nine months ended September 30, 2010.

In the nine months ended September 30, 2011 and 2010, we recorded a $0.9 million gain on the sale of an oil and gas related property. In the nine months ended September 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):

	Third Quarter				Nine Months
	2011		2010		2011		2010

General and administrative expenses	$	1,588	$	1,629	$	8,460	$	8,153
Exploration expenses		1,194		1,363		7,033		7,282
Main Pass Energy Hub costs		20		52		125		266
Total stock-based compensation cost	$	2,802	$	3,044	$	15,618	$	15,701

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 nine months ended September 30, 2011 was $10.76. We recorded $7.4 million in charges related to immediately vested stock options in the first nine 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 nine months ended September 30, 2010 was $10.18.

As of September 30, 2011, total compensation cost related to unvested, approved stock option awards not yet recognized in earnings was approximately $17.4 million, which is expected to be recognized over a weighted average period of approximately one year.

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Non-Operating.

Interest expense, net of amounts capitalized, totaled $0.6 million in the third quarter of 2011 and $8.8 million for the nine months ended September 30, 2011 compared with $8.7 million in the third quarter of 2010 and $29.1 million for the nine months ended September 30, 2010. Capitalized interest totaled $12.7 million in the third quarter of 2011, $3.1 million in the third quarter of 2010, $33.2 million for the nine months ended September 30, 2011 and $6.3 million for the nine months ended September 30, 2010. The increased capitalized interest for both periods is related to increased ownership interests in in-progress drilling projects due to the PXP Acquisition and other continuing exploratory drilling activity.

Discontinued Operations.

Our discontinued operations incurred net losses of $1.5 million in the third quarter of 2011 and $4.7 million for the nine months ended September 30, 2011 compared with losses of $1.2 million in the third quarter of 2010 and $4.3 million for the nine months ended September 30, 2010. The future estimated closure costs primarily for our former terminal facilities at Port Sulphur, Louisiana approximate $5.6 million at September 30, 2011, which is expected to be funded in the fourth quarter 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):

	Nine Months Ended
	September 30,
	2011			2010
Continuing operations
Operating	$	190.0		$	120.3
Investing		(413.0	)		(157.3	)
Financing		(28.9	)		(23.6	)


Discontinued operations
Operating	(11.5	)	(0.6	)
Investing	-		-
Financing	-		-

Total cash flow
Operating	178.5		119.7
Investing	(413.0	)	(157.3	)
Financing	(28.9	)	(23.6	)

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

Operating Cash Flows.

Operating cash flow increased $58.8 million for the nine months ended September 30, 2011 compared to the same period in 2010 primarily a result of $98.1 million of higher revenue offset by approximately $24.8 million of higher production and delivery costs and $22.6 million in additional reclamation expenditures.

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 $403.9 million for the nine months ended September 30, 2011 and $160.3 million for the nine months ended September 30, 2010. This increase is primarily due to our increased drilling activities and higher working interests 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 $27.6 million in the nine months ended September 30, 2011. During the nine months ended September 30, 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

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we have approximately 14,000 shares of our 8% preferred stock outstanding as of September 30, 2011. In the nine months ended September 30, 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 $23.1 million during the nine months ended September 30, 2010. During this period, we agreed through privately negotiated transactions to induce the conversion of approximately 64,200 shares of 8% preferred stock into approximately 9.4 million shares of common stock for a payment of $12.2 million.

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 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 credit facility are substantially the same as our prior credit facility. There were no borrowings outstanding under the credit facility during the quarter ended September 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 that is redetermined semi-annually beginning in November 2011 and each April and October thereafter.

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 September 30, 2011.

Exchange Offer for 5¼% Convertible Senior Notes

On October 6, 2011, we completed an offer to exchange up to $74,720,000 aggregate principal amount of our 5¼% Convertible Senior Notes due 2011 (Existing Notes). Existing Notes in the principal amount of $68,177,000 were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due 2012 (New Notes). We repaid $6,543,000 of the remaining principal amount of Existing Notes, which matured in accordance with their terms on October 6, 2011. The terms of the New Notes are substantially identical to the terms of the Existing Notes, except that the New Notes have a maturity date of October 6, 2012. The impact of this exchange transaction, which will be recorded as a modification of debt in the fourth quarter of 2011, will result in the recognition of an approximate $2.6 million debt discount related to the fair value of the instruments’ embedded conversion option that will be accreted as a component of interest expense over the term of the New Notes.

Senior Notes and Convertible Senior Notes

The following debt instruments were outstanding as of September 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 $13.2 discount (due 2017)		186.8
Credit facility		-
Total debt	$	561.5

For additional information regarding our outstanding debt terms and related transactions, see Note 6 of our 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 September 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 nine months ended September 30, 2011. As of September 30, 2011, we have

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recognized a liability of $12.7 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 our 2010 Form 10-K.

NEW ACCOUNTING STANDARDS

We do not expect the adoption of any accounting standards in 2011 to have a material impact on 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 acquired properties, 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 at wells operated by third parties where we are a participant), changes in oil and natural gas reserve expectations, the potential adoption of new governmental regulations, unanticipated hazards of which we have limited or not insurance coverage, failure of third party partners to fulfill their capital and other 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 retain 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 Part 1, Item 1A 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 September 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 .

There have been no material changes to the risk factors disclosed in Item 1A. Risk Factors of our 2010 Form 10-K and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011.

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 September 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

July 1-31, 2011	-	$ -		-	300,000
August 1-31, 2011	-	-		-	300,000
September 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 September 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: November 9, 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
4.1	Registration Rights Agreement dated as of September 8, 2011 by and among McMoRan Exploration Co. and Whitney Exploration, LLC		8-K	001-7791	09/09/2011
4.2	Indenture dated October 6, 2011 by and among McMoRan Exploration Co. and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to the 5¼% Convertible Senior Notes due 2012		8-K	001-07791	10/11/2011
10.1	Purchase and Sale Agreement by and between McMoRan Exploration Co., McMoRan Oil & Gas LLC, as buyer, Whitney Exploration, LLC, as seller, and Stephen J. Williams, dated as of September 8, 2011		8-K	001-07791	09/09/2011
15.1	Letter dated November 9, 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