McMoran Exploration (MMR) 10-Q 2012 Q3 Quarterly report

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, 2012
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 ÿ 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 ÿ 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 ÿ
Non-accelerated filer ÿ (Do not check if a smaller reporting company)		Smaller reporting company ÿ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.  ÿYes S No On October 31, 2012, there were issued and outstanding 161,880,866 shares of the registrant’s common stock, par value $0.01 per share.

McMoRan Exploration Co.
TABLE OF CONTENTS
	Page
Part I.  Financial Information
Item 1.  Financial Statements:
Condensed Consolidated Balance Sheets (Unaudited)	3
Consolidated Statements of Operations (Unaudited)	4
Consolidated Statements of Comprehensive Income (Loss) (Unaudited)	5
Consolidated Statements of Cash Flow (Unaudited)	6
Consolidated Statement of Equity (Unaudited)	7
Notes to Condensed Consolidated Financial Statements (Unaudited)	8
Report of Independent Registered Public Accounting Firm	25
Item 2.  Management's Discussion and Analysis
of Financial Condition and Results of Operations	26
Item 3.  Quantitative and Qualitative Disclosures about Market Risk	41
Item 4.  Controls and Procedures	41
Part II.  Other Information
Item 1.  Legal Proceedings	41
Item 1A.  Risk Factors	41
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 6.  Exhibits	42
Signature	43
Exhibit Index	E-1

Part I.  FINANCIAL INFORMATION

Item 1. Financial Statements.

McMoRan EXPLORATION CO.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In Thousands)

	September 30,		December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	191,934	$	568,763
Accounts receivable		56,044		72,085
Inventories		35,551		36,274
Prepaid expenses		16,636		9,103
Current assets from discontinued operations, including restricted cash
of $473		797		682
Total current assets		300,962		686,907
Property, plant and equipment, net		2,378,285		2,181,926
Restricted cash and other		62,575		61,617
Deferred costs		9,023		8,325
Long-term assets from discontinued operations		439		439
Total assets	$	2,751,284	$	2,939,214
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	89,635	$	115,832
Accrued liabilities		145,779		160,822
Accrued interest and dividends payable		20,704		14,448
Current portion of accrued oil and gas reclamation costs		64,571		58,810
5¼% convertible senior notes due October 2012		345		66,223
Other current liabilities		6,480		-
Current liabilities from discontinued operations, including sulphur reclamation costs		2,717		5,264
Total current liabilities		330,231		421,399
5¼% convertible senior notes due October 2013		67,832		-
11.875% senior notes		300,000		300,000
4% convertible senior notes		188,943		187,363
Accrued oil and gas reclamation costs		227,279		267,584
Other long-term liabilities		19,896		20,886
Other long-term liabilities from discontinued operations, including sulphur reclamation costs		18,624		19,018
Total liabilities		1,152,805		1,216,250
Stockholders' equity		1,598,479		1,722,964
Total liabilities and stockholders' equity	$	2,751,284	$	2,939,214

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)

(In Thousands, Except Per Share Amounts)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Revenues:
Oil and natural gas	$	88,097		$	134,548		$	282,387		$	423,729
Service		3,679			3,635			10,331			9,766
Total revenues		91,776			138,183			292,718			433,495
Costs and expenses:
Production and delivery costs		47,925			61,182			118,734			161,050
Depletion, depreciation and amortization expense		29,926			66,730			116,649			248,738
Exploration expenses		48,895			18,158			122,763			78,832
General and administrative expenses		12,111			11,877			38,760			39,052
Main Pass Energy Hub™ costs		114			49			210			562
Insurance recoveries		-			(22,649	)		(1,229	)		(52,018	)
Gain on sale of oil and gas properties		-			-			(799	)		(900	)
Total costs and expenses		138,971			135,347			395,088			475,316
Operating income (loss)		(47,195	)		2,836			(102,370	)		(41,821	)
Interest expense, net		-			(629	)		-			(8,782	)
Loss on debt exchange		(5,955	)		-			(5,955	)		-
Other income, net		88			204			525			614
Income (loss) from continuing operations before income taxes		(53,062	)		2,411			(107,800	)		(49,989	)
Income tax expense		-			-			-			-
Income (loss) from continuing operations		(53,062	)		2,411			(107,800	)		(49,989	)
Loss from discontinued operations		(645	)		(1,489	)		(5,573	)		(4,722	)
Net income (loss)		(53,707	)		922			(113,373	)		(54,711	)
Preferred dividends and inducement payments for early
conversion of convertible preferred stock		(10,306	)		(10,342	)		(30,990	)		(32,457	)
Net loss applicable to common stock	$	(64,013	)	$	(9,420	)	$	(144,363	)	$	(87,168	)
Basic and diluted net loss per share of common
stock:
Continuing operations		$(0.39	)		$(0.05	)		$(0.86	)		$(0.52	)
Discontinued operations		(0.01	)		(0.01	)		(0.03	)		(0.03	)
Net loss per share of common stock		$(0.40	)		$(0.06	)		$(0.89	)		$(0.55	)
Average common shares outstanding:
Basic and diluted		161,812			159,195			161,627			158,505

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited)

(In Thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Net income (loss)	$	(53,707	)	$	922		$	(113,373	)	$	(54,711	)
Other comprehensive loss:
Amortization of previously unrecognized pension components, net		(10	)		(10	)		(30	)		(30	)
Comprehensive income (loss)		(53,717	)		912			(113,403	)		(54,741	)
Preferred dividends and inducement payments for early conversion of convertible preferred stock		(10,306	)		(10,342	)		(30,990	)		(32,457	)
Comprehensive loss applicable to common stock	$	(64,023	)	$	(9,430	)	$	(144,393	)	$	(87,198	)

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)

(In Thousands)

	Nine Months Ended
	September 30,
	2012			2011
Cash flow from operating activities:
Net loss	$	(113,373	)	$	(54,711	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss from discontinued operations		5,573			4,722
Depletion, depreciation and amortization expense		116,649			248,738
Exploration drilling and related expenditures, net		93,468			42,046
Loss on debt exchange		5,955			-
Compensation expense associated with stock-based awards		14,011			15,618
Reclamation expenditures, net		(48,224	)		(93,411	)
Increase in restricted cash		(3,754	)		(3,760	)
Gain on sale of oil and gas properties		(799	)		(900	)
Amortization of deferred financing costs and other		(498	)		4,162
(Increase) decrease in working capital:
Accounts receivable		15,721			(47,648	)
Accounts payable and accrued liabilities		(15,139	)		68,058
Prepaid expenses and inventories		1,761			7,056
Net cash provided by continuing operations		71,351			189,970
Net cash used in discontinued operations		(8,823	)		(11,457	)
Net cash provided by operating activities		62,528			178,513
Cash flow from investing activities:
Exploration, development and other capital expenditures		(415,627	)		(403,889	)
Acquisition of oil and gas properties		-			(10,000	)
Deposits received for pending divestitures		6,480			-
Proceeds from sale of oil and gas properties		745			900
Net cash used in continuing operations		(408,402	)		(412,989	)
Net cash from discontinued operations		-			-
Net cash used in investing activities		(408,402	)		(412,989	)
Cash flow from financing activities:
Dividends paid and inducement payments on early conversion of convertible preferred stock		(30,990	)		(27,609	)
Credit facility refinancing fees		-			(1,712	)
Debt and equity issuance costs		(59	)		(543	)
Proceeds from exercise of stock options and other		94			929
Net cash used in continuing operations		(30,955	)		(28,935	)
Net cash from discontinued operations		-			-
Net cash used in financing activities		(30,955	)		(28,935	)
Net decrease in cash and cash equivalents		(376,829	)		(263,411	)
Cash and cash equivalents at beginning of year		568,763			905,684
Cash and cash equivalents at end of period	$	191,934		$	642,273
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 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, 2012

(In Thousands)

	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, 2011	$	713,999		$	1,639	$	2,178,775		$	(1,123,449	)	$	216		$	(48,216	)	$	1,722,964
Stock-based compensation
expense		-			-		14,011			-			-			-			14,011
Preferred stock dividends		-			-		(30,990	)		-			-			-			(30,990	)
Preferred stock conversions		(1,881	)		3		1,878			-			-			-			-
Stock option exercises and other, net		-			5		2,638			-			-			(2,532	)		111
Premium resulting from 5 ¼ % convertible senior notes exchange		-			-		5,786			-			-			-			5,786
Net loss		-			-		-			(113,373	)		-			-			(113,373	)
Other comprehensive income (loss)		-			-		-			-			(30	)		-			(30	)
Balance as of September 30, 2012	$	712,118		$	1,647	$	2,172,098		$	(1,236,822	)	$	186		$	(50,748	)	$	1,598,479

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 condensed consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware corporation, are prepared in accordance with U.S. generally accepted accounting principles.  McMoRan’s condensed 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 currently includes the pursuit of a potential deepwater port facility/terminal to receive, store and condition natural gas for offloading to floating liquefaction storage and offloading vessels for export at the Main Pass Energy HubTM (MPEH™) 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 condensed 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, 2011 (2011 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.

New Accounting Standard

In June 2011, the Financial Accounting Standards Board issued an Accounting Standards Update (ASU) in connection with guidance on the presentation of comprehensive income. This ASU requires an entity to present the components of net income and other comprehensive income and total comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This ASU was effective for McMoRan’s 2012 interim reporting, and McMoRan adopted this ASU by presenting comprehensive income as a separate statement in this Form 10-Q for the three- and nine-month periods ended September 30, 2012 and 2011. The adoption of this accounting standard had no other impact on McMoRan’s financial position or results of operations.

2.  LONG-TERM DEBT

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

	September 30,			December 31,
	2012			2011
11.875% senior notes	$	300,000		$	300,000
5¼% convertible senior notes (new notes)		67,832			-
5¼% convertible senior notes (old notes), net of discount of $0 and $1,954		345			66,223
4% convertible senior notes, net of discount of $11,057 and $12,637		188,943			187,363
Senior secured revolving credit facility		-			-
Total debt		557,120			553,586
Less current maturities		(345	)		(66,223	)
Total long-term debt	$	556,775		$	487,363

Senior Secured Revolving Credit Facility

McMoRan has a variable rate senior secured revolving credit facility (credit facility) that is secured by substantially all of MOXY’s oil and gas properties and matures on June 30, 2016, provided that the facility will mature on August 16, 2014 if McMoRan’s 11.875% senior notes are not redeemed or refinanced with senior notes with a term extending at least through 2016 by that date.  The credit facility’s borrowing capacity is $150 million, and under certain conditions it may be increased to a capacity of $300 million

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with additional lender commitments. There were no borrowings outstanding under the credit facility as of September 30, 2012. After giving effect to a $100 million letter of credit outstanding as surety support to a third party associated with reclamation obligations, availability under the credit facility totaled $50 million.

Availability under the credit facility is subject to a borrowing base that is redetermined semi-annually each April and October. In July 2012, in connection with the semi-annual redetermination of McMoRan’s borrowing base, McMoRan’s lenders affirmed the $150 million borrowing base until the next redetermination and subject to McMoRan providing a first priority lien on $35 million of cash deposited in a separate deposit account which will remain in place until the next redetermination during the fourth quarter of 2012.  Use of the cash is unrestricted; however, to the extent McMoRan uses any portion of the cash prior to completion of the next redetermination, the borrowing base would be reduced on a dollar for dollar basis.

The credit facility includes covenants and other restrictions customary for oil and gas borrowing base credit facilities. McMoRan is currently in compliance with these covenants.

Exchange Offer for 5¼% Convertible Senior Notes

On September 13, 2012, McMoRan completed an offer to exchange up to $68.2 million aggregate principal amount of its 5¼% Convertible Senior Notes due October 6, 2012 (5¼% old notes).  Approximately $67.8 million aggregate principal amount of the 5¼% old notes were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due October 6, 2013 (5¼% new notes).  McMoRan repaid $0.3 million of the remaining principal amount of the 5¼% old notes, which matured in accordance with their terms on October 6, 2012.  The terms of the 5¼% new notes are identical to the terms of the 5¼% old notes, except that the 5¼% new notes have a maturity date of October 6, 2013. The impact of this exchange transaction, which was recorded as a debt extinguishment in the third quarter of 2012, resulted in a loss on debt exchange of $6.0 million.  The fair value of the 5¼% new notes at the exchange date ($73.6 million) resulted in a debt premium of approximately $5.8 million, the impact of which was recorded as a component of McMoRan’s loss on debt exchange with an offsetting adjustment to additional paid-in-capital.

Fair Value of Debt

The fair value of McMoRan’s 5¼% old notes, 5¼% new notes, 11.875% senior notes due November 2014 (11.875% notes) and 4% convertible senior notes due December 2017 (4% convertible notes) is determined at the end of each reporting period using level 2 inputs based upon prices for exchanges of such instruments in other recent transactions by other market participants.  The following table reflects the estimated fair value of these obligations as of September 30, 2012 and December 31, 2011 (in thousands):

	September 30,		December 31,
	2012		2011
5¼% new notes	$	73,618	$	-
5¼% old notes		345		73,590
11.875% notes		317,250		318,000
4% convertible notes		203,424		232,600

Interest Expense, Net

Interest expense, which includes the amortization of deferred financing costs and credit facility fees, is reflected net of amounts capitalized to McMoRan’s in-progress drilling projects. Interest capitalized by McMoRan totaled $13.9 million in the third quarter of 2012 and $42.4 million for the nine months ended September 30, 2012. Capitalized interest totaled $12.7 million in the third quarter of 2011 and $33.2 million for the nine months ended September 30, 2011.

3.  EARNINGS PER SHARE

Basic net loss per share of common stock has been calculated by dividing McMoRan’s 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 conversion inducement payments.

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McMoRan had net losses from continuing operations (as defined above) in the three- and nine-month periods ended September 30, 2012 and 2011. Accordingly, the incremental common shares that would have been issued upon exercise of stock options, as well as conversion of McMoRan’s 5.75% convertible perpetual preferred stock (5.75% preferred stock), 8% convertible perpetual preferred stock (8% preferred stock), 4% convertible notes and 5¼% new notes and 5¼% old 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, meaning 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
	2012		2011		2012		2011
Stock options a		1,213		1,338		991		1,478
Shares issuable upon assumed
conversion of:
5.75% preferred stock b		43,750		43,750		43,750		43,750
8% preferred stock b		1,980		2,046		1,841		2,219
5¼% new notes and 5¼% old notes c		4,113		4,508		4,113		4,508
4% notes c		12,500		12,500		12,500		12,500

a.   McMoRan uses the treasury stock method to determine total shares related to in-the-money stock options for purposes of its diluted loss 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.

b.   Amount represents total equivalent common shares assuming conversion of the 5.75% preferred stock and 8% preferred stock. During the nine months ended September 30, 2011, McMoRan induced conversion of approximately 8,100 shares of its 8% preferred stock (Note 7).  Preferred stock dividends and inducement payments for the early conversion of shares of McMoRan’s 8% preferred stock totaled $10.3 million and $31.0 million for the three- and nine-month periods ended September 30, 2012, respectively and $10.3 million and $32.4 million for the three- and nine-month periods ended September 30, 2011, respectively.  See Note 8 of the 2011 Form 10-K for additional information regarding McMoRan’s 5.75% preferred stock and 8% preferred stock.

c.   There was no net interest expense on the 5¼% new notes or the 4% convertible notes during the three- and nine-month periods ended September 30, 2012. Interest expense, net on the 5¼% old notes totaled $0.1 million and $0.7 million, respectively during the three- and nine-month periods ended September 30, 2011 and interest expense, net on the 4% convertible notes totaled $0.1 million and $1.6 million, respectively, during the three and nine-month periods ended September 30, 2011. Additional information regarding McMoRan’s 4% convertible notes and 5¼% old notes is disclosed in Note 6 of the 2011 Form 10-K.

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

	Third Quarter				Nine Months
	2012		2011		2012		2011
Outstanding options (in thousands)		10,511		8,574		11,778		5,327
Average exercise price	$	16.16	$	16.88	$	15.74	$	17.78

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4.  STOCK-BASED COMPENSATION

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

	Third Quarter				Nine Months
	2012		2011		2012		2011
Stock options awarded to employees and directors	$	2,363	$	2,542	$	12,746	$	14,659
Stock options awarded to non-employees		168		136		928		642
Restricted stock units		98		124		337		317
Total stock-based compensation cost	$	2,629	$	2,802	$	14,011	$	15,618

A summary of the classification of stock-based compensation by financial statement line item for the third quarter of 2012 and 2011 and nine-months ended September 30, 2012 and 2011 follows (in thousands):

	Third Quarter				Nine Months
	2012		2011		2012		2011
General and administrative expenses	$	1,697	$	1,588	$	7,817	$	8,460
Exploration expenses		932		1,194		6,157		7,033
Main Pass Energy Hub costs		-		20		37		125
Total stock-based compensation cost	$	2,629	$	2,802	$	14,011	$	15,618

On February 6, 2012, McMoRan’s Board of Directors granted 1,953,500 stock options to its employees at an exercise price of $13.00 per share, including immediately exercisable options for an aggregate of 445,000 shares.  Options for these 445,000 shares were issued to McMoRan’s Co-Chairmen and Treasurer in lieu of cash compensation in 2012. On June 1, 2012 McMoRan granted 120,000 stock options and 30,000 restricted stock units to its non-employee directors and advisory directors. The exercise price for the directors’ stock options was $8.82 per share. The weighted average per share fair value of the 2,073,500 options granted during the nine months ended September 30, 2012 was $8.61.  McMoRan recorded $6.0 million in charges related to immediately vested stock options during the nine months ended September 30, 2012. 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, under the terms of McMoRan’s employee stock option plans, results in one-year’s compensation expense being immediately recognized at the effective date of the stock option grant.  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. On June 1, 2011 McMoRan granted 120,000 stock options and 30,000 restricted stock units to its non-employee directors and advisory directors. The exercise price for the directors’ stock options was $17.60 per share. The weighted average per share fair value of the 1,857,500 options granted during the nine months ended September 30, 2011 was $10.76.  McMoRan recorded $7.4 million in charges related to immediately vested stock options during the nine months ended September 30, 2011.

As of September 30, 2012, total compensation cost related to nonvested approved stock option awards not yet recognized in earnings was approximately $18.5 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 2011 Form 10-K.

5.  INCOME TAXES

As of September 30, 2012 and December 31, 2011, McMoRan had approximately $497.1 million and $459.4 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 2011 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.

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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 condensed consolidated financial statements.  Currently, McMoRan’s major taxing jurisdictions are the United States (federal) and Louisiana.  Tax periods open to audit primarily include federal income tax returns subsequent to 2008 and Louisiana income tax returns subsequent to 2007.  Net operating loss amounts prior to this time are also subject to audit.

6. OIL AND GAS ACTIVITIES

Exploration and Operations.

McMoRan has incurred drilling costs for in-progress and/or unproven exploratory wells totaling $1,018.7 million at September 30, 2012. In addition, McMoRan’s allocated costs for the working interests acquired in properties associated with McMoRan’s current in-progress and unproven wells totaled $693.5 million at September 30, 2012.

As of September 30, 2012, McMoRan had four wells (the Davy Jones initial discovery well - “Davy Jones No. 1”, the Davy Jones offset appraisal well - “Davy Jones No. 2”, Blackbeard West No. 1 and Hurricane Deep) with costs that have been capitalized for a period in excess of one year following the completion of initial exploratory drilling operations.

Completion activities are currently in progress on the Davy Jones No. 1 well, and completion activities for the Davy Jones No. 2 well are planned to commence following the Davy Jones No. 1 completion, testing, and production assessment process. McMoRan’s total investment in the Davy Jones complex, which includes $474.8 million in allocated property acquisition costs, totaled $961.0 million at September 30, 2012.

The Blackbeard West No. 1 well was drilled to a total depth of 32,997 feet in October 2008 and logs below 30,067 feet indicated potential hydrocarbon bearing zones measuring 220 net feet requiring further evaluation.  The well has been temporarily abandoned while McMoRan evaluates whether to drill deeper or complete the well to test the existing zones. McMoRan’s investment in the Blackbeard West No. 1 drilling costs approximated $31.3 million at September 30, 2012. The Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal Block 188 is currently drilling below 24,300 feet.  As previously reported, logging data indicate the presence of potential low-resistivity pay zones, one of which is approximately 80 feet thick and requires further evaluation.  In addition, wireline logs encountered Middle Miocene sands below 22,500 feet with 24 percent porosity, which have potential hydrocarbon columns on water. McMoRan has applied for a permit to deepen Blackbeard West No. 2 to 25,500 feet to evaluate additional deeper miocene objectives.  McMoRan holds a 69.4 percent working interest and a 53.1 percent net revenue interest in Ship Shoal Block 188.  McMoRan’s investment in Blackbeard West No. 2 totaled $71.5 million at September 30, 2012. In addition, McMoRan has approximately $27.6 million of allocated property acquisition costs for the Blackbeard West unit.

The Hurricane Deep well, 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 while McMoRan evaluates opportunities to sidetrack or deepen the well. McMoRan’s total investment in Hurricane Deep, which includes $24.8 million in allocated costs associated with the Plains Exploration Production Company (PXP) property acquisition in late 2010, totaled $55.5 million at September 30, 2012. See Note 2 of the 2011 Form 10-K for information regarding the PXP Acquisition.

The Blackbeard East ultra-deep exploration by-pass well, which is located on South Timbalier Block 144 in 80 feet of water, was drilled to a total depth of 33,318 feet in January 2012.  Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate.  Pressure and temperature data below the salt weld in the Miocene sands between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. McMoRan’s lease rights to South Timbalier Block 144 were scheduled to expire on August 17, 2012. Prior to the expiration, McMoRan submitted initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE). McMoRan is seeking approval to test and complete the upper Miocene sands during 2013 using

12

conventional equipment and technologies.  Additional plans for further development of the deeper zones continue to be evaluated. McMoRan continues to hold its rights to this lease while its development plans are under administrative consideration by BSEE. McMoRan’s ability to continue to preserve its interest in Blackbeard East will require approval from the BSEE of its development plans.

McMoRan holds a 72.0 percent working interest and a 57.4 percent net revenue interest in Blackbeard East.  McMoRan’s total investment in Blackbeard East, which includes $130.5 million in allocated property acquisition costs, totaled $305.9 million at September 30, 2012.

The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Upper Eocene, and Sparta carbonate. McMoRan’s lease rights to Eugene Island Block 223 were scheduled to expire on October 8, 2012. Prior to the lease expiration, McMoRan submitted its initial development plans for Lafitte to the BSEE. McMoRan continues to hold its rights to this lease while its development plans are under administrative consideration by the BSEE. McMoRan’s ability to continue to preserve its interest in Lafitte will require approval from the BSEE of its development plans.

McMoRan holds a 72.0 percent working interest and a 58.3 percent net revenue interest in Lafitte.  McMoRan’s total investment in Lafitte, which includes $35.8 million in allocated property acquisition costs, totaled $194.7 million at September 30, 2012.

McMoRan’s statements of operations for the third quarter and nine-months ended September 30, 2012 results include charges to exploration expense primarily resulting from the write-off of allocated carrying value of leasehold costs from the December 2010 property acquisition no longer being pursued totaling $37.2 million. See Note 2 of the 2011 Form 10-K for information regarding the PXP Acquisition.

The Boudin deep gas exploration well, which was located in 20 feet of water on Eugene Island Block 26 was drilled to a total depth of 24,284 feet in October 2011. Drilling results indicated potential hydrocarbon bearing zones within a laminated sand section in the Rob-L of the Miocene. McMoRan’s lease at Eugene Island Block 26 was set to expire during the second quarter of 2012. Prior to the expiration, McMoRan requested a lease extension from the BSEE to provide McMoRan additional time required to assess potential alternatives for a completion. On June 15, 2012, McMoRan received notice from the BSEE that its request to extend the Boudin lease was denied. As a result, McMoRan recorded a charge to exploration expense to fully impair its investment in Boudin of approximately $55.7 million in the second quarter of 2012.

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 2011 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 2011 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.  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 a 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

13

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 from that property, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required.

McMoRan recorded no impairment charges relating to its proved properties in the third quarter of 2012 and recorded $11.7 million in impairment charges in the nine months ended September 30, 2012, following an impairment assessment of the carrying value of its proved oil and gas properties. The impairment charges recorded in the nine months ended September 30, 2012 were primarily due to higher than anticipated recompletion costs, a decline in market prices earlier in 2012, certain well performance issues, and other economic factors. In the third quarter of 2011 and nine months ended September 30, 2011, McMoRan recorded impairment charges relating to its proved properties totaling $11.3 million and $62.0 million, respectively. The charges incurred during the third quarter of 2011 related to declines in market prices for both oil and natural gas and the impact of increased capitalized costs for certain properties related to asset retirement obligation adjustments. In addition to the third quarter of 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. McMoRan considers the fair value measurements used in its impairment evaluations to be derived from Level 3 inputs.

Additional impairment charges may be recorded in future periods if prices weaken, or if other unforeseen operational or other 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 2011 Form 10-K.

2008 Hurricane Activity.

In December 2011, McMoRan reached a settlement with its insurers to finalize all outstanding claims from the 2008 hurricane events. As a result, McMoRan recognized no insurance recoveries relating to the 2008 hurricane claims during the nine months ended September 30, 2012, although, approximately $1.2 million of insurance proceeds related to a separate property damage claim were recorded in the nine months ended September 30, 2012. Net insurance recoveries of $22.6 million and $52.0 million, respectively, related to the 2008 hurricane events were recorded during the third quarter of 2011 and nine months ended September 30, 2011.

Accrued Reclamation Obligations.

For more information regarding McMoRan’s accounting policies for asset retirement obligations see Notes 1 and 15 of the 2011 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, 2011 follows (in thousands):

	Oil and
	Natural Gas			Sulphur
Asset retirement obligations at January 1, 2012	$	326,394		$	17,745
Liabilities settled		(65,780	)		(3,583	)
Scheduled accretion and other expense		27,158	a		3,584
Other, net		4,078			-
Asset retirement obligations at September 30, 2012	$	291,850		$	17,746

14

a.   Includes $16.3 million in reclamation adjustments for asset retirement obligations associated with certain oil and gas properties.

Property Divestitures.

On October 2, 2012, McMoRan completed the sale of three Gulf of Mexico Shelf oil and gas properties in the West Delta and Mississippi Canyon areas (the Assets) for cash consideration of $23.3 million (after closing adjustments) and the assumption of related abandonment obligations.  The Assets represent approximately one percent of McMoRan’s total average daily production for the third quarter of 2012 and three percent of its total estimated reserves at June 30, 2012.  Independent reserve engineers’ estimates of proved reserves for the Assets at June 30, 2012, totaled approximately 942,000 barrels of oil and 1.7 billion cubic feet of natural gas (7.4 billion cubic feet of natural gas equivalents).  The transaction was effective July 1, 2012.

McMoRan expects to complete in the fourth quarter of 2012 the previously announced sale of a package of traditional Gulf of Mexico shelf oil and gas properties in the Eugene Island area, for cash consideration before closing adjustments of $36.8 million and the assumption of related abandonment obligations. The assets represent approximately six percent of McMoRan’s total average daily production for the third quarter of 2012 and six percent of its total estimated reserves at June 30, 2012.  Independent reserve engineers’ estimates of proved reserves at June 30, 2012 approximated 15.2 billion cubic feet of natural gas equivalents, with approximately 78 percent from natural gas and 21 percent proved developed producing.  The transaction will be effective July 1, 2012 and is subject to the completion of certain customary closing conditions.

The combined cash proceeds from the two transactions before closing adjustments will total $64.8 million and assumed reclamation obligations will total $43.4 million.  McMoRan expects to record net gains totaling approximately $40 million in the fourth quarter of 2012 in connection with these transactions. McMoRan may consider additional sales of noncore assets.

Property Acquisition.

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.  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 impact to McMoRan’s statements of operations on a pro forma basis.

7. OTHER MATTERS

8% Preferred Stock Conversions.

During the third quarter of 2012, 1,881 shares of McMoRan’s 8% preferred stock were converted with a liquidation preference of $1.9 million into approximately 0.3 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). Following this transaction, 12,118 shares of McMoRan’s 8% preferred stock remain outstanding.

During the nine months ended September 30, 2011, McMoRan privately negotiated the 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).  To induce the early conversion of these shares of 8% preferred stock, McMoRan paid an aggregate of $1.5 million in cash to the holder of these shares, which was recorded as a component of preferred dividends and inducement payments for early conversion of preferred stock in the first quarter of 2011.

15

Subsequent Events Evaluation.

McMoRan evaluated subsequent events for purposes of its September 30, 2012 financial reporting through the date of filing of its quarterly report on Form 10-Q with the Securities and Exchange Commission.

8.  GUARANTOR FINANCIAL STATEMENTS

MOXY is an unconditional guarantor of McMoRan’s 11.875% notes.  See Notes 6 and 18 of the 2011 Form 10-K for additional information regarding the 11.875% 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, 2012 and December 31, 2011, the related condensed consolidating statements of operations for the three- and nine-month periods ended September 30, 2012 and 2011 and cash flow for the nine-month periods ended September 30, 2012 and 2011, which should be read in conjunction with the notes to these condensed consolidated financial statements:

16

CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)

September 30, 2012

(In Thousands)

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan
ASSETS
Current assets:
Cash and cash equivalents	$	18	$	191,817	$	99		$	-		$	191,934
Accounts receivable		2,516		53,468		60			-			56,044
Inventories		-		35,551		-			-			35,551
Prepaid expenses		759		15,877		-			-			16,636
Current assets from discontinued
operations		-		-		797			-			797
Total current assets		3,293		296,713		956			-			300,962
Property, plant and equipment, net		-		2,378,254		31			-			2,378,285
Investment in subsidiaries		1,517,231		-		-			(1,517,231	)		-
Amounts due from affiliates		657,570		-		-			(657,570	)		-
Restricted cash and other assets		3,666		67,932		-			-			71,598
Long-term assets from discontinued operations		-		-		439			-			439
Total assets	$	2,181,760	$	2,742,899	$	1,426		$	(2,174,801	)	$	2,751,284
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	404	$	89,112	$	119		$	-		$	89,635
Accrued liabilities		1,159		144,679		1			(60	)		145,779
Current portion of debt		345		-		-			-			345
Current portion of oil and gas
accrued reclamation costs		-		64,571		-			-			64,571
Other current liabilities		19,950		7,234		-			-			27,184
Current liabilities from discontinued
operations		-		-		2,657			60			2,717
Total current liabilities		21,858		305,596		2,777			-			330,231
Long-term debt		556,775		-		-			-			556,775
Amounts due to affiliates		-		653,017		4,553			(657,570	)		-
Accrued oil and gas reclamation costs		-		227,279		-			-			227,279
Other long-term liabilities		4,648		13,632		1,616			-			19,896
Long-term liabilities from discontinued
operations		-		-		18,624			-			18,624
Total liabilities		583,281		1,199,524		27,570			(657,570	)		1,152,805
Commitments and contingencies
Stockholders’ equity (deficit)		1,598,479		1,543,375		(26,144	)		(1,517,231	)		1,598,479
Total liabilities and stockholders’ equity
(deficit)	$	2,181,760	$	2,742,899	$	1,426		$	(2,174,801	)	$	2,751,284

17

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2011

(In Thousands)

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan
ASSETS
Current assets:
Cash and cash equivalents	$	16,341	$	552,365	$	57		$	-		$	568,763
Accounts receivable		1,850		70,235		-			-			72,085
Inventories		-		36,274		-			-			36,274
Prepaid expenses		668		8,435		-			-			9,103
Current assets from discontinued
operations		-		-		682			-			682
Total current assets		18,859		667,309		739			-			686,907
Property, plant and equipment, net		-		2,181,896		30			-			2,181,926
Investment in subsidiaries		1,596,091		-		-			(1,596,091	)		-
Amounts due from affiliates		677,128		-		-			(677,128	)		-
Restricted cash and other assets		4,641		65,301		-			-			69,942
Long-term assets from discontinued operations		-		-		439			-			439
Total assets	$	2,296,719	$	2,914,506	$	1,208		$	(2,273,219	)	$	2,939,214
LIABILITIES AND STOCKHOLDERS’ EQUITY  (DEFICIT)
Current liabilities:
Accounts payable	$	217	$	115,121	$	494		$	-		$	115,832
Accrued liabilities		787		160,309		-			(274	)		160,822
Current portion of debt		66,223		-		-			-			66,223
Current portion of oil and gas
accrued reclamation costs		-		58,810		-			-			58,810
Other current liabilities		13,694		754		-			-			14,448
Current liabilities from discontinued
operations		-		-		4,990			274			5,264
Total current liabilities		80,921		334,994		5,484			-			421,399
Long-term debt		487,363		-		-			-			487,363
Amounts due to affiliates		-		674,613		2,515			(677,128	)		-
Accrued oil and gas reclamation costs		-		267,584		-			-			267,584
Other long-term liabilities		5,471		13,799		1,616			-			20,886
Long-term liabilities from discontinued
operations		-		-		19,018			-			19,018
Total liabilities		573,755		1,290,990		28,633			(677,128	)		1,216,250
Stockholders’ equity (deficit)		1,722,964		1,623,516		(27,425	)		(1,596,091	)		1,722,964
Total liabilities and stockholders’
equity (deficit)	$	2,296,719	$	2,914,506	$	1,208		$	(2,273,219	)	$	2,939,214

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Three Months Ended September 30, 2012

(In Thousands)

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
Revenues:
Oil and natural gas	$	-		$	88,097		$	-		$	-		$	88,097
Service		-			3,679			9			(9	)		3,679
Total revenues		-			91,776			9			(9	)		91,776
Costs and expenses:
Production and delivery costs		-			47,934			-			(9	)		47,925
Depletion, depreciation and amortization
expense		-			29,926			-			-			29,926
Exploration expenses		-			48,895			-			-			48,895
General and administrative expenses		3,266			8,845			-			-			12,111
Main Pass Energy HubTM costs		-						114			-			114
Total costs and expenses		3,266			135,600			114			(9	)		138,971
Operating loss		(3,266	)		(43,824	)		(105	)		-			(47,195	)
Equity in losses of consolidated
subsidiaries		(44,487	)		-			-			44,487			-
Loss on debt exchange		(5,955	)		-			-			-			(5,955	)
Other income, net		1			87			-			-			88
Loss from continuing operations
before income taxes		(53,707	)		(43,737	)		(105	)		44,487			(53,062	)
Income tax expense		-			-			-			-			-
Loss from continuing operations		(53,707	)		(43,737	)		(105	)		44,487			(53,062	)
Loss from discontinued operations		-			-			(645	)		-			(645	)
Net loss		(53,707	)		(43,737	)		(750	)		44,487			(53,707	)
Preferred dividends and other related
preferred stock costs		(10,306	)		-			-			-			(10,306	)
Net loss applicable to common stock	$	(64,013	)	$	(43,737	)	$	(750	)	$	44,487		$	(64,013	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Nine Months Ended September 30, 2012

(In Thousands)

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
Revenues:
Oil and natural gas	$	-		$	282,387		$	-		$	-		$	282,387
Service		-			10,331			26			(26	)		10,331
Total revenues		-			292,718			26			(26	)		292,718
Costs and expenses:
Production and delivery costs		-			118,760			-			(26	)		118,734
Depletion, depreciation and amortization
expense		-			116,649			-			-			116,649
Exploration expenses		-			122,763			-			-			122,763
General and administrative expenses		7,758			31,002			-			-			38,760
Main Pass Energy HubTM costs		-			-			210			-			210
Insurance recoveries		-			(1,229	)		-			-			(1,229	)
Gain on sale of oil and gas property		-			(799	)		-			-			(799	)
Total costs and expenses		7,758			387,146			210			(26	)		395,088
Operating loss		(7,758	)		(94,428	)		(184	)		-			(102,370	)
Interest expense, net		-			-			-			-			-
Equity in losses of consolidated
subsidiaries		(99,649	)		-			-			99,649			-
Loss on debt exchange		(5,955	)		-			-			-			(5,955	)
Other income (expense), net		(11	)		536			-			-			525
Loss from continuing operations before
income taxes		(113,373	)		(93,892	)		(184	)		99,649			(107,800	)
Income tax expense		-			-			-			-			-
Loss from continuing operations		(113,373	)		(93,892	)		(184	)		99,649			(107,800	)
Loss from discontinued operations		-			-			(5,573	)		-			(5,573	)
Net loss		(113,373	)		(93,892	)		(5,757	)		99,649			(113,373	)
Preferred dividends and other related
preferred stock costs		(30,990	)		-			-			-			(30,990	)
Net loss applicable to common stock	$	(144,363	)	$	(93,892	)	$	(5,757	)	$	99,649		$	(144,363	)

20

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Three Months Ended September 30, 2011

(In Thousands)

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
Revenues:
Oil and natural gas	$	-		$	134,548		$	-		$	-		$	134,548
Service		-			3,635			9			(9	)		3,635
Total revenues		-			138,183			9			(9	)		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 HubTM costs		-			-			49			-			49
Insurance recoveries		-			(22,649	)		-			-			(22,649	)
Total costs and expenses		2,228			133,079			49			(9	)		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

(In Thousands)

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
Revenues:
Oil and natural gas	$	-		$	423,729		$	-		$	-		$	423,729
Service		-			9,766			25			(25	)		9,766
Total revenues		-			433,495			25			(25	)		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 HubTM 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			562			(25	)		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 CASH FLOW (UNAUDITED)

Nine Months Ended September 30, 2012

(In Thousands)

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
Cash flow from operating activities:
Net cash provided by (used in)
continuing operations	$	(2,483	)	$	74,006		$	(172	)	$	71,351
Net cash used in discontinued operations		-			-			(8,823	)		(8,823	)
Net cash provided by (used in)
operating activities		(2,483	)		74,006			(8,995	)		62,528
Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(415,627	)		-			(415,627	)
Deposits received for pending divestitures		-			6,480			-			6,480
Proceeds from sale of oil and gas property		-			745			-			745
Net cash used in investing activities		-			(408,402	)		-			(408,402	)
Cash flow from financing activities:
Dividends paid		(30,990	)		-			-			(30,990	)
Proceeds from exercise of stock options		128			(34	)		-			94
Debt and equity issuance costs		(59	)		-			-			(59	)
Investment from parent		(7,000	)		-			7,000			-
Amounts payable to consolidated affiliates		24,081			(26,118	)		2,037			-
Net cash provided by (used in)
financing activities		(13,840	)		(26,152	)		9,037			(30,955	)
Net decrease in cash and cash
equivalents		(16,323	)		(360,548	)		42			(376,829	)
Cash and cash equivalents at beginning
of year		16,341			552,365			57			568,763
Cash and cash equivalents at end of
period	$	18		$	191,817		$	99		$	191,934

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW (UNAUDITED)

Nine Months Ended September 30, 2011

(In Thousands)

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
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

9. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan recognized a loss from continuing operations totaling $107.8 million for the nine months ended September 30, 2012, which was inadequate to cover its fixed charges of $42.7 million for the nine months ended September 30, 2012. McMoRan recognized a loss from continuing operations totaling $50.0 million for the nine months ended September 30, 2011, which was inadequate to cover its fixed charges of $42.3 million for the nine months ended September 30, 2011.  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, 2012, and the related consolidated statements of operations and comprehensive income (loss) for the three and nine-month periods ended September 30, 2012 and 2011 and cash flow for the nine-month periods ended September 30, 2012 and 2011, and the consolidated statement of equity for the nine-month period ended September 30, 2012. 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, 2011, and the related consolidated statements of operations, cash flow and changes in stockholders’ equity for the year then ended (not presented herein), and in our report dated February 29, 2012, 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, 2011, 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 2, 2012

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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, 2011 (2011 Form 10-K) filed with the Securities and Exchange Commission (SEC).  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 Condensed Consolidated Financial Statements included elsewhere in this Form 10-Q.  Also see the 2011 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 920,000 gross acres, including approximately 385,000 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.  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% convertible notes). See Notes 2, 6, and 8 of the 2011 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.

On October 2, 2012, we completed the sale of three Gulf of Mexico shelf oil and gas properties in the West Delta and Mississippi Canyon areas (the Assets) for cash consideration of $23.3 million (after closing adjustments) and the assumption of related abandonment obligations.  The Assets represent approximately one percent of our total average daily production for the third quarter of 2012 and three percent of our total estimated reserves at June 30, 2012.  Independent reserve engineers’ estimates of proved reserves for the Assets at June 30, 2012, totaled approximately 942,000 barrels of oil and 1.7

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billion cubic feet of natural gas (7.4 billion cubic feet of natural gas equivalents).  The transaction was effective July 1, 2012.

We expect to complete in the fourth quarter of 2012 the previously announced sale of a package of traditional Gulf of Mexico shelf oil and gas properties in the Eugene Island area, for cash consideration before closing adjustments of $36.8 million and the assumption of related abandonment obligations. The assets repreesnt approximately six percent of our total average daily production for the third quarter of 2012 and six percent of our total estimated reserves at June 30, 2012.  Independent reserve engineers’ estimates of proved reserves at June 30, 2012 approximated 15.2 billion cubic feet of natural gas equivalents, with approximately 78 percent from natural gas and 21 percent proved developed producing.  The transaction will be effective July 1, 2012 and is subject to the completion of certain customary closing conditions.

The combined cash proceeds from the two transactions before closing adjustments will total $64.8 million and assumed reclamation obligations will total $43.4 million.  We expect to record net gains totaling approximately $40 million in the fourth quarter of 2012 in connection with these transactions. McMoRan may consider additional sales of noncore assets.

During the nine months ended September 30, 2012, we invested $415.6 million on capital-related projects associated with our exploration and development activities. Depending on drilling results, follow on development opportunities and general market factors, we expect 2012 capital expenditures to approximate $550 million apportioned evenly between exploration and development. During the nine months ended September 30, 2012, we also incurred $48.2 million of net abandonment expenditures.  We plan to spend approximately $80 million in 2012 for the abandonment and removal of oil and gas structures in the Gulf of Mexico.

Substantial capital expenditures have been and will continue to be required in our exploration and development activities, especially for the development and exploitation of our Davy Jones and other significant ultra-deep exploration and development projects.  Our capital expenditures have been financed in part with internally generated cash from operations, the continued availability of which is dependent on a number of variables including production from our existing proved reserves, sales prices for natural gas and oil, and our ability to acquire, locate and produce new reserves.  We have also financed our capital expenditures with proceeds from debt and equity financings and participation by partners in exploration and development projects.  Our ongoing exploration and development activities will require substantial additional financial resources.  We are currently engaged in discussions regarding financing of our future exploration and development activities as we continue to evaluate market conditions and funding alternatives, including potential asset sales, additional debt or equity financing, joint venture transactions or other financing arrangements.

North American Natural Gas and Oil Market Environment

Our third quarter 2012 production volumes were comprised of approximately 63 percent natural gas and 37 percent oil and natural gas liquids, while our revenues were derived 73 percent from oil and natural gas liquids and 27 percent from natural gas. North American natural gas averaged $2.89 per one million British thermal units (MMbtu) during the third quarter of 2012.  The spot price for natural gas was $3.69 per MMbtu on October 31, 2012.  The average oil price for the third quarter of 2012 was $92.29 per barrel and the spot price for oil was $86.24 per barrel on October 31, 2012.  Future oil and natural gas prices are subject to change and these changes are not within our control (see Part 1, Item 1A. “Risk Factors” included in the 2011 Form 10-K).

Currently, natural gas supply is higher than related demand. Natural gas prices have recently improved on lower than expected injections into storage. Recent gas inventory reductions were driven by warmer-than-normal weather conditions and coal displacement. While market observers expect near-term prices to remain under pressure, some analysts expect gas prices to improve longer term with industry-led drilling directed to oil and liquids plays, reduced shale wells drilling activity and industrial consumption increases in response to low prices.  Early in the second quarter of 2012, the spot price for natural gas fell below $2.00 per MMbtu, although recently natural gas prices have improved from the 10-year lows seen earlier in 2012. Prolonged weak natural gas market conditions would likely have a negative impact on our

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results of operations and financial condition and may require us to reduce planned capital spending and adjust aspects of our current business strategy.

OPERATIONAL ACTIVITIES

Production

Production from the Gulf of Mexico Outer Continental Shelf (GOM Shelf) generally declines at a faster rate than in other producing regions of the world, as the related reservoirs are generally sandstone reservoirs characterized by high porosity and high permeability. Because of this, related reserves are produced over a relatively short duration, with recovery of a higher percentage of reserves during the earlier years of production. In addition, our typical operational practice is to produce from the lowest zones of a reservoir until the reserves in such zone are depleted and then establish recompletions in the next higher zone within the reservoir until all reserves are produced. For each reservoir, this practice generally results in declining production volumes until production from higher zones commences.

The overall impact of these factors is that our oil and natural gas reserves generally are represented by an accelerating production decline curve that is offset by recompletions, new discoveries and/or purchased reserves being brought on production. To the extent we are unable to acquire or generate additional production from new sources, our production levels will decline over time, which declines will generally become more pronounced as our oil and natural gas reserves mature. The following table reflects our average daily production levels for the three and nine-month periods ended September 30, 2012 and 2011:

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	Third Quarter				Nine Months
	2012		2011		2012		2011
Average Daily Production (one million cubic feet equivalent, per day (MMcfe/d))		134		187		143		193

Third-quarter 2012 production averaged 134 MMcfe/d net to us, compared with 187 MMcfe/d in the third quarter of 2011.  In addition to the factors discussed above, our third-quarter 2012 production was impacted by unplanned downtime associated with Hurricane Isaac, which impacted Gulf of Mexico operations prior to making landfall on the coast of Louisiana in late August 2012.

Production from our Flatrock field averaged a gross rate of approximately 112 MMcfe/d (46 MMcfe/d net to us) in the third quarter of 2012, and as anticipated was lower than the year ago period which averaged 164 MMcfe/d (67 MMcfe/d net to us).  Following depletion of currently producing zones at Flatrock field, we are planning several recompletions to additional pay zones which are expected to increase production in future years.  We own a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

The historical production rates discussed above do not reflect the potential positive impact of future production from certain of our ultra-deep oil and gas discoveries, including the Davy Jones No. 1 well which is pending final completion and flow testing and others for which we are evaluating and developing completion plans. We believe these discoveries, if successfully completed and brought on production, will increase our production levels. However, there is no assurance whether or to what extent we will be successful in this regard, and continuing declines in our production could negatively impact our operating cash flows, results of operations and financial condition.

Production is expected to average approximately 137 MMcfe/d for the year 2012, including 120 MMcfe/d in the fourth quarter of 2012.  Our estimated production rates are dependent on the timing of planned recompletions, production performance, weather and other factors.

Oil and Gas Activities

Shallow WaterUltra-Deep Exploration Activities.  Since 2008, our drilling activities in the shallow waters of the Gulf of Mexico (GOM) below the salt weld (i.e. listric fault) have successfully confirmed our geologic model and the highly prospective nature of this emerging geologic trend.  The data from five wells drilled to date indicate the presence below the salt weld of geologic formations including Upper/Middle/Lower Miocene, Frio, Vicksburg, Upper Eocene, Sparta carbonate, Wilcox, Tuscaloosa and Cretaceous carbonate, which have been prolific onshore, in the deepwater GOM and in international locations.  The results of these activities indicate the potential for a major new geologic trend spanning 200 miles in the shallow waters of the GOM and onshore in the Gulf Coast area.  Further drilling and flow testing will be required to determine the ultimate potential of this new trend.

Davy Jones

At Davy Jones No. 1, we successfully cleaned out the wellbore to approximately 28,630 feet which will enable testing of all 165 feet of perforated sand sections in the Wilcox.  Operations to clear the wellbore of the heavy drilling mud used to suppress flow in the well required more time than expected following Hurricane Isaac because residual barite material hardened at the perforations in the bottom of the wellbore while operations were interrupted.  Operations are continuing to prepare the well for flow testing which would be the first shallow water, ultra-deep sub-salt completion on the GOM Shelf.  Commercial production is expected shortly thereafter.  Timing of these activities depend on operating conditions in the well and other factors.

Completion and testing of the Davy Jones offset appraisal well (Davy Jones No. 2) is expected to commence following review of results from Davy Jones No. 1.  Davy Jones is located on a 20,000 acre structure that has multiple additional drilling opportunities.

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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.

Davy Jones involves a large ultra-deep structure encompassing four GOM Shelf lease blocks (20,000 acres).  We are the operator and 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 $474.8 million in allocated property acquisition costs, totaled $961.0 million at September 30, 2012.

Blackbeard East

The Blackbeard East ultra-deep exploration by-pass well, which is located on South Timbalier Block 144 in 80 feet of water, was drilled to a total depth of 33,318 feet in January 2012.  Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate.  Pressure and temperature data below the salt weld in the Miocene sands between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. Our lease rights to South Timbalier Block 144 were scheduled to expire on August 17, 2012. Prior to the expiration, we submitted initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE). We are seeking approval to test and complete the upper Miocene sands during 2013 using conventional equipment and technologies.  Additional plans for further development of the deeper zones continue to be evaluated. We continue to hold our rights to this lease while our development plans are under administrative consideration by BSEE. Our ability to continue to preserve our interest in Blackbeard East will require approval from the BSEE of our development plans.

We hold a 72.0 percent working interest and a 57.4 percent net revenue interest in Blackbeard East.  Our total investment in Blackbeard East, which includes $130.5 million in allocated property acquisition costs, totaled $305.9 million at September 30, 2012.

Lafitte

The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Upper Eocene, and Sparta carbonate. Our lease rights to Eugene Island Block 223 were scheduled to expire on October 8, 2012. Prior to the lease expiration, we submitted our initial development plans for Lafitte to the BSEE. We continue to hold our rights to this lease while our development plans are under administrative consideration by the BSEE. Our ability to continue to preserve our interest in Lafitte will require approval from the BSEE of our development plans.

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 $35.8 million in allocated property acquisition costs, totaled $194.7 million at September 30, 2012.

Blackbeard West Unit

The Blackbeard West No. 1 well was drilled to a total depth of 32,997 feet in October 2008 and logs below 30,067 feet indicated potential hydrocarbon bearing zones measuring 220 net feet requiring further evaluation.  The well has been temporarily abandoned while we evaluate whether to drill deeper or complete the well to test the existing zones. Our investment in the Blackbeard West No. 1 drilling costs approximated $31.3 million at September 30, 2012.

The Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal Block 188 is currently drilling below 24,300 feet.  As previously reported, logging data indicate the presence of potential low-resistivity pay zones, one of which is approximately 80 feet thick and requires further evaluation.  In addition, wireline logs encountered Middle Miocene sands below 22,500 feet with 24 percent porosity, which have potential hydrocarbon

30

columns on water.  The presence of sands with high porosity is significant, indicating that sands can retain excellent characteristics in a high-temperature, high-pressure environment on the Shelf below the salt weld.  We have applied for a permit to deepend Blackbeard West No. 2 to 25,500 feet to evaluate additional deeper miocene objectives.  We hold a 69.4 percent working interest and a 53.1 percent net revenue interest in Ship Shoal Block 188.  Our investment in Blackbeard West No. 2 totaled $71.5 million at September 30, 2012. In addition, we have approximately $27.6 million of allocated property acquisition costs for the Blackbeard West unit.

Lineham Creek

The Lineham Creek exploration prospect, which is located onshore in Cameron Parish, Louisiana is currently drilling below the salt weld at 24,400 feet.  The well, which is targeting Eocene and Paleocene objectives below the salt weld, has a proposed total depth of 29,000 feet.  Chevron U.S.A. Inc., as operator of the well, holds a 50 percent working interest.  Lineham Creek is approximately 55 miles northwest of Davy Jones.  We are participating for a 36.0 percent working interest. Our investment in Lineham Creek totaled $41.6 million at September 30, 2012.

Lomond North

On September 19, 2012 drilling commenced in the Highlander area on the Lomond North ultra-deep prospect.  Lomond North, which is located in St. Martin Parish, LA, is currently drilling below 8,700 feet.  This exploratory well has a proposed total depth of 30,000 feet and is targeting Eocene, Paleocene and Cretaceous objectives below the salt weld.  Lomond North is approximately 65 miles north of Davy Jones. We are operator and currently hold a 72.0 percent working interest.  Our investment in Lomond North totaled $23.1 million at September 30, 2012.

Hurricane Deep

The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block 217, was drilled to a total depth of 21,378 feet in July 2011.  Log results indicated the presence of Operc and Gyro sands that we determined could be pursued in an updip location.The well has been temporarily abandoned to preserve the wellbore while we evaluate opportunities to sidetrack or deepen the well. Our total investment in Hurricane Deep, which includes $24.8 million in allocated property acquisition costs associated with the PXP acquisition, totaled $55.5 million at September 30, 2012.

If current or future activities are not successful in generating production that will allow us to recover all or a portion of our investment in any of our in-progress and/or unproven wells, we may be required to write down our investment in such properties to their estimated fair value.

Other

In 2010, we farmed out our 70.0 percent working interest in a portion of West Cameron Block 73 to a third party operator and retained a 5 percent of 8/8ths overriding royalty interest (ORRI).  Recently, the operator encountered positive drilling results and is evaluating completion opportunities to develop the approximate 400 net feet of pay identified in seven sands between 14,500 feet and nearly 18,000 feet.  In addition to benefiting from the 5 percent ORRI, production from the well will be processed through our existing West Cameron Block 73 “A” platform under which we will collect processing fees.  Additionally, following these positive exploratory results we are considering additional drilling opportunities on the West Cameron Block 73 structure.  We hold a 70 percent working interest in various depths across the entire 5,000 acre block including deep rights.

Recently Acquired Leases

The BOEM has awarded us all 14 leases from the June 2012 Central Gulf of Mexico Lease Sale 216/222 (lease sale) held in New Orleans, Louisiana.  Six of the 14 bids were sole bids by us and the remaining eight bids were made jointly with Chevron U.S.A. Inc. These blocks enhance McMoRan’s shallow water, ultra-deep exploration acreage in and around Davy Jones West, England, Calico Jack, Barataria, Captain Blood and Lafitte.

Acreage Position

Including the 14 leases from the lease sale discussed above, we currently control interests in 1,001 oil and gas leases in the GOM and onshore Louisiana and Texas covering approximately 920,000 gross acres (555,000 acres net to our interests). Our acreage position includes approximately 700,000 gross acres (425,000 acres net to our interests) located on the outer continental shelf of the GOM. This

31

acreage position includes approximately 385,000 gross acres associated with our ultra-deep gas play. We believe the ultra-deep sub-salt play extends onshore and are pursuing acreage associated with large structures we have identified onshore South Louisiana. Leases covering approximately 40,000 net acres controlled by us are scheduled to expire over the remainder of 2012, however, a significant portion of this acreage is expected to be retained by drilling operations or other means.

RESULTS OF OPERATIONS

Our third quarter 2012 operating loss of $47.2 million includes (a) adjustments totaling approximately $3.1 million charged against earnings for increased asset retirement obligations associated with certain of our non-producing oil and gas properties; (b) $37.2 million in charges to exploration expense primarily resulting from the write-off of allocated carrying value of leasehold costs from the December 2010 property acquisition no longer being pursued; (c) $2.6 million in charges related to stock-based compensation expense; (d) a $6.0 million loss on the 5¼% convertible senior notes exchange; and excludes (e) approximately $13.9 million in interest expense capitalized to in-progress drilling projects.

Our operating loss of $102.4 million for the nine months ended September 30, 2012 reflects (a) impairment charges of $11.7 million for certain fields to reduce their net carrying value to fair value; (b) adjustments totaling approximately $16.3 million charged against earnings for increased asset retirement obligations associated with certain of our non-producing oil and gas properties; (c) $93.5 million in charges to exploration expense primarily resulting from the write-off of allocated carrying value of leasehold costs from the December 2010 property acquisition no longer being pursued and the lease expiration associated with our interest in Eugene Island 26 (Boudin well); (d) $14.0 million in charges related to stock-based compensation expense; (e) a $6.0 million loss on the 5¼% convertible senior notes exchange; and excludes (f) approximately $42.4 million in interest expense capitalized to in-progress drilling projects.

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 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 non-productive well costs and certain unproven leasehold cost reductions.

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Summarized operating data are as follows:

	Third Quarter		Nine Months
	2012	2011	2012	2011
Sales volumes:
Gas (thousand cubic feet, or Mcf)	7,652,600	11,367,900	24,740,600	34,638,200
Oil (barrels)	534,800	674,700	1,650,800	2,139,800
Natural gas liquids (NGLs, in barrels)	241,500	292,700	772,400	856,300
Average realizations
Gas (per Mcf)	$      3.12	$      4.38	$      2.70	$      4.54
Oil (per barrel)	$  103.43	$  100.94	$  108.68	$  102.56
NGLs (per barrel)	$    36.42	$    56.35	$    46.41	$    54.04

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	$	134,548		$	423,729
Increase (decrease)
Price realizations:
Natural gas		(9,642	)		(45,523	)
Oil and condensate		1,332			10,103
Sales volumes:
Natural gas		(16,273	)		(44,935	)
Oil and condensate		(14,122	)		(50,152	)
NGL revenue		(7,699	)		(10,431	)
Other		(47	)		(404	)
Oil and natural gas revenues – current year period	$	88,097		$	282,387

Our oil and natural gas sales volumes totaled 12.3 billion cubic feet of natural gas equivalents (Bcfe) in the third quarter of 2012, a 28 percent decrease from the 17.2 Bcfe of sales volume generated in the third quarter of 2011. The decrease in sales volumes between comparable periods is primarily due to the expected production decline curve associated with certain of our maturing oil and gas properties. Average realizations received for natural gas sold during the third quarter of 2012 decreased 29 percent from amounts received in the comparable period of 2011 while average realizations received for oil sold during the third quarter of 2012 were relatively comparable to the same period in 2011 (see “North American Natural Gas and Oil Market Environment” above).  Our service revenues totaled $3.7 million in the third quarter of 2012 and $3.6 million in the same period in 2011.

Our oil and natural gas sales volumes totaled 39.3 billion cubic feet of natural gas equivalents (Bcfe) in the nine months ended September 30, 2012, a 25 percent decrease from the 52.6 Bcfe of sales volume generated in the nine months ended September 30, 2011. The decrease in sales volumes between comparable periods is primarily due to the expected production decline curve associated with certain of our maturing oil and gas properties. Average realizations received for natural gas sold during the nine months ended September 30, 2012 decreased 41 percent from amounts received in the comparable period of 2011 and average realizations received for oil sold during the nine months ended September 30, 2012 increased 6 percent from amounts received in the comparable period of 2011 (see “North American Natural Gas and Oil Market Environment” above).  Our service revenues totaled $10.3 million in the nine months ended September 30, 2012 and $9.8 million in the same period in 2011.

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Production and delivery costs.The following table reflects our production and delivery costs for the third quarter of 2012 and 2011 and nine months ended September 30, 2012 and 2011 (in millions, except per Mcfe amounts):

	Third Quarter				Nine Months
		Per		Per			Per		Per
	2012	Mcfe	2011	Mcfe	2012		Mcfe	2011	Mcfe
Lease operating expense	$27.3	$2.21	$27.1	$1.58	$77.6		$1.98	$85.4	$1.62
Workover and major expense costs	11.8	0.96	24.9	1.45	17.7		0.45	42.3	0.80
Insurance	3.9	0.32	1.6	0.09	7.7		0.19	12.7	0.24
Transportation, production taxes, and plant processing fees	4.9	0.40	6.9	0.40	15.9		0.40	19.3	0.37
Other	-	-	0.7	0.04	(0.2	)	-	1.4	0.03
Total	$47.9	$3.89	$61.2	$3.56	$118.7		$3.02	$161.1	$3.06

On a per unit basis lease operating expense (LOE) increased $0.63 per Mcfe in the third quarter of 2012 compared to the same period in 2011 largely due to certain fixed costs allocated over a declining production base between the periods and higher LOE costs for Main Pass 299 and certain other fields incurred in the third quarter of 2012 compared to the prior third quarter period. LOE decreased approximately $7.8 million in the nine months ended September 30, 2012, compared to the same period in 2011, due to a decrease in overall production between the periods partially offset by the higher LOE costs in the third quarter of 2012 referred to above. Workover and major expense costs decreased approximately $13.1 million and $24.6 million in the third quarter of 2012 and nine months ended September 30, 2012, respectively, compared to the same periods in 2011, primarily due to an unproductive workover drilling project totaling approximately $15.3 million during the third quarter of 2011 and certain prior year regulatory related compliance repairs incurred at our Main Pass 299 facility during the nine months ended September 30, 2011.

Market insurance premium rates for operators in the Gulf of Mexico have increased 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 generally become 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 2011 renewal of our annual insurance program. The elimination of windstorm coverage resulted in a reduction of our insurance costs for the nine months ended September 30, 2012 in comparison to the same period in 2011.

We renewed our insurance coverage effective June 2012 including coverage for well control up to $150 million for conventional  wells and up to $250 million for ultra-deep wells.  Both the limits of coverage and deductibles for this coverage  are scaled to our working interest in the covered location. As part of the June 2012 renewal,  we also obtained partial coverage for losses resulting from named windstorms for a limited number of our properties. Coverage under this named windstorm policy has an annual aggregate limit of $60 million (net to us) subject to an $11.5 million deductible for each windstorm event. 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. The June 2012 increased coverage contributed to an increase in our insurance costs for the third quarter of 2012 in comparison to the same period in 2011. For additional information related to risks associated with our insurance coverage, see Part I, Item 1A. “Risk Factors” included in the 2011 Form 10-K.

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Depletion, depreciation and amortization expense.   The following table reflects the components of our depletion, depreciation and amortization (DD&A) expense for the third quarter of 2012 and 2011 and nine months ended September 30, 2012 and 2011 (in millions, except per Mcfe amounts):

	Third Quarter				Nine Months
		Per		Per		Per		Per
	2012	Mcfe	2011	Mcfe	2012	Mcfe	2011	Mcfe
Depletion and depreciation expense	$23.2	$1.82	$41.4	$2.41	$77.7	$1.98	$130.0	$2.47
Accretion expense	6.7	0.52	14.0	0.82	27.2	0.69	56.7	1.08
Impairment charges/losses	-	-	11.3	0.66	11.7	0.30	62.0	1.18
Total	$29.9	$2.34	$66.7	$3.89	$116.6	$2.97	$248.7	$4.73

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 decrease in depletion and depreciation expense in the third quarter of 2012 and nine months ended September 30, 2012 compared to the same periods in 2011 is primarily related to lower sales volumes in 2012 compared to 2011 and the impact of a declining depreciable base of proved oil and gas properties that has been reduced in recent years through unit-of-production reserve depletion and impairment charges.

The decrease in accretion expense in the third quarter of 2012 compared to the third quarter of 2011 primarily resulted from a decrease in adjustments to oil and gas property asset retirement obligations. During the third quarter of 2011 approximately $10.4 million of asset retirement obligation adjustments were recorded related to estimated remediation costs for hurricane damaged and certain other properties compared with $3.1 million of such adjustments related to other on-going abandonment projects in the third quarter of 2012. During the nine month ended September 30, 2011 approximately $46.0 million of asset retirement obligation adjustments were recorded related to estimated remediation costs for hurricane damaged and certain other properties compared with $16.3 million of such adjustments relating to other on-going abandonment projects in the nine months ended September  30, 2012.

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 no impairment charges relating to our proved properties in the third quarter of 2012 and $11.7 million during the nine months ended September 30, 2012, following an impairment assessment of the carrying value of our proved oil and gas properties. The impairment charge incurred during the nine months ended September 30, 2012 was primarily due to higher than anticipated recompletion costs for a certain property, a decline in market prices earlier in 2012, certain well performance issues, and other economic factors. In the third quarter of 2011 and nine months ended September 30, 2011, we recorded impairment charges totaling $11.3 million and $62.0 million, respectively. The charges incurred during the third quarter of 2011 related to declines in market prices for both oil and natural gas and the impact of increased capitalized costs for certain properties related to asset retirement obligation adjustments. In addition to the third quarter of 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.

As more fully explained in Part 1, Item 1A, “Risk Factors” included in the 2011 Form 10-K any one or more of the conditions described above could require additional impairment charges to be recorded in future periods.

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

	Third Quarter						Nine Months
	2012			2011			2012			2011
Geological and geophysical
including 3-D seismic purchases a	$	3.1		$	6.4		$	12.4		$	17.2
Non-productive exploratory costs, including
related lease costs		37.2	b		3.1	c		93.5	b		42.0	c
Other d		8.6			8.7			16.9			19.6
	$	48.9		$	18.2		$	122.8		$	78.8

a.   Includes compensation costs associated with outstanding stock-based awards totaling $0.9 million in the third quarter of 2012 and $6.2 million in the nine months ended September 30, 2012 compared with $1.2 million and $7.0 million of compensation costs during comparable periods of 2011 (see “Stock-Based Compensation” below).

b.   Includes a $37.2 million charge in the third quarter of 2012 primarily for  the write-off of allocated carrying value of leasehold costs from the December 2010 property acquisition no longer being pursued and the $56.3 million lease expiration charge associated with our interest in Eugene Island 26 (Boudin well) in the second quarter of 2012.

c.   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.

d.   Includes $4.5 million and $12.0 million in stand-by rig charges in the third quarter of 2012 and nine months ended September 30, 2012, respectively. Includes $3.8 million and $7.6 million in stand-by rig charges in the third quarter of 2011 and nine months ended September 30, 2011, respectively.  Includes $4.1 million and $4.9 million in drilling related insurance and other costs for the third quarter of 2012 and nine months ended September 30, 2012, respectively. Includes $4.9 million and $12.0 million in drilling related insurance and other costs for the third quarter of 2011 and nine months ended September 30, 2011, respectively.

Other Financial Results

Operating.  

General and administrative expense totaled $12.1 million in the third quarter of 2012 and $38.8 million in the nine months ended September 30, 2012 compared to $11.9 million in the third quarter of 2011 and $39.1 million in the nine months ended September 30, 2011.

In December 2011, we reached a settlement with our insurers to finalize all outstanding claims from the 2008 hurricane events. As a result, we recognized no insurance recoveries relating to the 2008 hurricane claims during the third quarter of 2012 or nine months ended September 30, 2012, although approximately $1.2 million of insurance proceeds related to a separate property damage claim was recorded in the nine months ended September 30, 2012. Net insurance recoveries of $22.6 million and $52.0 million related to the 2008 hurricane claims were recorded during the third quarter of 2011 and nine months ended September 30, 2011, respectively.

During the nine months ended September 30, 2012, we recorded a $0.8 million gain on the sale of an oil and gas producing property. In the nine months ended September 30, 2011, we recorded a $0.9 million gain on the sale of our interest in a natural gas processing facility.

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

	Third Quarter				Nine Months
	2012		2011		2012		2011
General and administrative expenses	$	1,697	$	1,588	$	7,817	$	8,460
Exploration expenses		932		1,194		6,157		7,033
Main Pass Energy Hub costs		-		20		37		125
Total stock-based compensation cost	$	2,629	$	2,802	$	14,011	$	15,618

On February 6, 2012, our Board of Directors granted 1,953,500 stock options to our employees at an exercise price of $13.00 per share, including immediately exercisable options for an aggregate of 445,000 shares.  Options for these 445,000 shares were issued to our Co-Chairmen and Treasurer in lieu of cash compensation in 2012. On June 1, 2012 we granted 120,000 stock options and 30,000 restricted stock units to our non-employee directors and advisory directors. The exercise price for the directors’ stock options was $8.82 per share. The weighted average per share fair value of the 2,073,500 options granted during the nine months ended September 30, 2012 was $8.61.  We recorded $6.0 million in charges related to immediately vested stock options during the nine months ended September 30, 2012. 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, under the terms of our employee stock option plans, results in one-year’s compensation expense being immediately recognized at the effective date of the stock option grant.  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. On June 1, 2011 we granted 120,000 stock options and 30,000 restricted stock units to our non-employee directors and advisory directors. The exercise price for the directors’ stock options was $17.60 per share. The weighted average per share fair 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 during the nine months ended September 30, 2011.

As of September 30, 2012, total compensation cost related to nonvested approved stock option awards not yet recognized in earnings was approximately $18.5 million, which is expected to be recognized over a weighted average period of approximately one year.

Non-Operating.  

All interest expense was capitalized during the third quarter and nine months ended September 30, 2012 and interest expense, net of amounts capitalized, totaled $0.6 million and $8.8 million in the third quarter of 2011 and nine months ended September 30, 2011, respectively.  Capitalized interest totaled $13.9 million and $42.4 million in the third quarter of 2012 and nine months ended September 30, 2012, respectively and totaled $12.7 million and $33.2 million in the third quarter of 2011 and nine months ended September 30, 2011, respectively. The increased amount of capitalized interest in 2012 reflects the impact of our increased investment in on-going drilling projects.

During the third quarter and nine months ended September 30, 2012 we recorded a $6.0 million loss related to the 5¼% convertible senior notes exchange transaction.

Discontinued Operations.

Our discontinued operations incurred net losses of $0.6 million in the third quarter of 2012 and $5.6 million for the nine months ended September 30, 2012 compared with losses of $1.5 million in the third quarter of 2011 and $4.7 million for the nine months ended September 30, 2011.  The nine months ended September 30, 2012 includes $2.7 million of adjustments related to increased cost estimates of reclamation activities associated with certain former sulphur mining related properties.

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LIQUIDITY AND CAPITAL RESOURCES

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,
	2012			2011
Continuing operations
Operating	$	71.4		$	190.0
Investing		(408.4	)		(413.0	)
Financing		(31.0	)		(28.9	)

Discontinued operations
Operating	(8.8	)	(11.5	)
Investing	-		-
Financing	-		-
Total cash flow
Operating	62.5		178.5
Investing	(408.4	)	(413.0	)
Financing	(31.0	)	(28.9	)

Nine-Month 2012 Cash Flows Compared with Nine-Month 2011 Cash Flows

Operating Cash Flows.                                                      

Our operating cash flow decreased $118.6 million in the nine months ended September 30, 2012 compared to the same period in 2011 primarily as a result of $140.8 million in lower revenues, $50.8 million in lower insurance recoveries, and $25.1 million in lower working capital sources between comparable periods, offset by $45.2 million in lower reclamation expenditures, $42.3 million in lower production and delivery costs and $8.8 million in lower interest expense.

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 $415.6 million for the nine months ended September 30, 2012 and $403.9 million for the nine months ended September 30, 2011.

Our investing cash flows for the third quarter of 2012 and nine months ended September 30, 2012 also include $6.5 million in deposits received for the fourth quarter 2012 divestitures discussed above.

Financing Cash Flows.                                                      

Our continuing operations’ financing activities included payments of dividends on our 5.75% preferred stock and our 8% convertible perpetual preferred stock (8% preferred stock) totaling $31.0 million and $32.5 million during the nine months ended September 30, 2012 and 2011, respectively. Additionally, 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.

Senior Secured Revolving Credit Facility

Our variable rate senior secured revolving credit facility (credit facility) is secured by substantially all of MOXY’s oil and gas properties and matures on June 30, 2016, provided that the facility will mature on August 16, 2014 if the 11.875% senior notes are not redeemed or refinanced with senior notes with a term extending at least through 2016 by that date.  The credit facility’s borrowing capacity is $150 million,

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and under certain conditions it may be increased to a capacity of $300 million with additional lender commitments. There were no borrowings outstanding under the credit facility as of September 30, 2012. 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 (Note 6 of the 2011 Form 10-K).

Availability under the credit facility is subject to a borrowing base that is redetermined semi-annually each April and October. In July 2012, in connection with the semi-annual redetermination of our borrowing base, our lenders affirmed the $150 million borrowing base until the next redetermination and subject to our providing a first priority lien on $35 million of cash deposited in a separate deposit account which will remain in place until the next redetermination during the fourth quarter of 2012.  Use of the cash is unrestricted; however, to the extent we use any portion of the cash prior to completion of the next redetermination, the borrowing base would be reduced on a dollar for dollar basis.

The credit facility includes covenants and other restrictions customary for oil and gas borrowing base credit facilities.  We are currently in compliance with these covenants.

Senior Notes and Convertible Senior Notes

The following debt instruments were outstanding as of September 30, 2012 (in millions):

	Amount
11.875% senior notes (due 2014)	$	300.0
5¼% convertible senior notes (5¼% new notes due 2013)		67.8
5¼% convertible senior notes (5¼% old notes due 2012)		0.3
4% convertible senior notes, net of $11.0 discount (due 2017)		189.0
Credit facility		-
Total debt	$	557.1

On September 13, 2012, we completed an offer to exchange up to $68.2 million aggregate principal amount of our 5¼% Convertible Senior Notes due October 6, 2012 (5¼% old notes).  Approximately $67.8 million aggregate principal amount of the 5¼% old notes were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due October 6, 2013 (5¼% new notes).  We repaid $0.3 million of the remaining principal amount of the 5¼% old notes, which matured in accordance with their terms on October 6, 2012.  The terms of the 5¼% new notes are identical to the terms of the old 5¼% notes, except that the 5¼% new notes have a maturity date of October 6, 2013. The impact of this exchange transaction, which was recorded as a debt extinguishment in the third quarter of 2012, resulted in a loss on debt exchange of $6.0 million.  The fair value of the 5¼% new notes at the exchange date ($73.6 million) resulted in a debt premium of approximately $5.8 million, the impact of which was recorded as a component of our loss on debt exchange with an offsetting adjustment to additional paid-in-capital.

For additional information regarding our outstanding debt terms and related transactions, see Note 6 of the 2011 Form 10-K.

Capital Resources

Substantial capital expenditures have been and will continue to be required in our exploration and development activities, especially for the development and exploitation of our Davy Jones and other significant ultra-deep exploration and development projects.  Our capital expenditures have been financed in part with internally generated cash from operations, the continued availability of which is dependent on a number of variables including production from our existing proved reserves, sales prices for natural gas and oil, and our ability to acquire, locate and produce new reserves.  We have also financed our capital expenditures with proceeds from debt and equity financings and participation by partners in exploration and development projects.  Our ongoing exploration and development activities

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will require substantial additional financial resources.  We are currently engaged in discussions regarding financing of our future exploration and development activities as we continue to evaluate market conditions and funding alternatives, including potential asset sales, additional debt or equity financing, joint venture transactions or other financing arrangements.

MAIN PASS ENERGY HUBTM PROJECT

Our long-term business objective of the Main Pass Energy HubTM (MPEHTM) is to maximize the value of the offshore structures used in our former sulphur operations located at our Main Pass facilities offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana.

Currently our subsidiary, Freeport-McMoRan Energy LLC, and a third party are engaged in efforts to utilize the MPEH™ as a potential deepwater port facility/terminal to receive, store and condition natural gas for offloading to floating liquefaction storage and offloading vessels located on-site for export. The project would utilize existing offshore structures of the MPEH™ deepwater port, which was approved by the U.S. Maritime Administration in 2007 as a deepwater port for the importation and regasification of LNG, conditioning of natural gas to produce NGLs, and storage of natural gas in salt caverns. Modification of the Main Pass facilities to accommodate use as an LNG export facility would require additional permit approvals.

On September 11, 2012, we and our partner filed an application with the Department of Energy (DOE) for long-term, multi-contract authorization to export domestically-produced liquefied natural gas (LNG). The DOE application seeks approval to export up to 24 million tonnes of LNG per annum (3.2 bcf per day) to countries with free trade agreements with the United States.  Preparation of a non-free trade agreement application is in progress.  MPEH™ is located close to significant Gulf Coast natural gas production and numerous interstate pipelines and offshore gathering systems.

We are engaged in studies to define the project and related permitting requirements and are developing commercial arrangements required to support the significant capital investments involved in the project.  The ultimate outcome of our efforts to enter into commercial arrangements on reasonable terms to develop the MPEH™ project and obtain additional financing to fund the project is subject to various uncertainties, many of which are beyond our control.  For additional information regarding the MPEHtm project, see “Main Pass Energy Hubtm Project” in Part I, Items 1. and 2. “Business and Properties” included in the 2011 Form 10-K.

NEW ACCOUNTING STANDARD

For information regarding our adoption of a new accounting standard, see Note 1 of the 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, oil and gas exploration, development and production activities and costs, amounts and timing of capital expenditures, reclamation, indemnification and environmental obligations and costs, the potential for or expectation of successful flow tests, potential quarterly and annual production and flow rates, reserve estimates, projected operating cash flows and liquidity, and the potential MPEHtm project. 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.

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

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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 for which we have limited or no 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 obtain regulatory approvals and significant project financing for the potential MPEHtm project, access to capital to fund drilling activities, as well as other general exploration and development risks and hazards, and other factors described in Part I, Item 1A. “Risk Factors” included in the 2011 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 significant changes in our market risks since the year ended December 31, 2011.

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, 2012 that has materially affected, or is reasonably likely to materially affect, our internal controls 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 from the risk factors disclosed in Part I, Item 1A. “Risk Factors” included in the 2011 Form 10-K.

41

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, 2012:

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, 2012	-	$             -		-	300,000
August 1-31, 2012	-	-		-	300,000
September 1-30, 2012	-	-		-	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, 2012 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.

42

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 2, 2012

43

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		10-K	001-07791	02/29/2012
3.2	Amended and Restated By-Laws of McMoRan as amended effective February 1, 2010		8-K	001-07791	02/03/2010
4.1	Form of Certificate of McMoRan Common Stock		S-4	333-61171	10/6/1998
4.2	First Supplemental Indenture dated as of November 14, 2007, by and between McMoRan and the Bank of New York, as trustee (related to the 11.875% Senior Notes due 2014)		8-K	001-07791	11/15/2007
4.3	Indenture dated December 30, 2010 by and among McMoRan and U.S. Bank National Association, as trustee		8-K	001-07791	01/04/2011
4.4	Indenture dated September 13, 2012 by and among McMoRan and The Bank of New York Mellon Trust Company, N.A., as Trustee		8-K	001-07991	09/13/2012
10.1	First Amendment to Credit Agreement among McMoRan Exploration Co., as parent, McMoRan Oil & Gas LLC, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, dated as of July 25, 2012	X
15.1	Letter dated November 2, 2012 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

E-1