McMoran Exploration (MMR) 10-Q 2008 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, 2008
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 oNo

      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 (Check one):

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities and Exchange Act of 1934). oYes S No

On September 30, 2008, there were issued and outstanding 70,469,713 shares of the registrant’s Common Stock, par value $0.01 per share.

McMoRan Exploration Co.
TABLE OF CONTENTS
	Page
Part I.  Financial Information
Financial Statements:
Condensed Consolidated Balance Sheets (Unaudited)	3
Consolidated Statements of Operations (Unaudited)	4
Consolidated Statements of Cash Flow (Unaudited)	5
Notes to Consolidated Financial Statements	6
Report of Independent Registered Public Accounting Firm	27
Management's Discussion and Analysis
of Financial Condition and Results of Operations	28
Quantitative and Qualitative Disclosures about Market Risks	44
Controls and Procedures	45
Part II.  Other Information	45
Signature	46
Exhibit Index	E-1

Part I.  FINANCIAL INFORMATION

Item 1. Financial Statements.

McMoRan EXPLORATION CO.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

	September 30,		December 31,
	2008		2007
	(In Thousands)
ASSETS
Cash and cash equivalents	$	160,635	$	4,830
Accounts receivable		115,712		128,690
Inventories		33,153		11,507
Prepaid expenses		19,171		14,331
Fair value of oil and gas derivative contracts		11,035		16,623
Current assets from discontinued operations, including restricted cash
of $0.5 million		3,175		3,029
Total current assets		342,881		179,010
Property, plant and equipment, net		1,316,850		1,503,359
Sulphur business assets, net		339		349
Restricted investments and cash		26,073		7,036
Fair value of oil and gas derivative contracts		1,182		4,317
Deferred financing costs		16,620		21,217
Total assets	$	1,703,945	$	1,715,288
LIABILITIES AND STOCKHOLDERS’ EQUITY
Accounts payable	$	105,606	$	97,821
Accrued liabilities		95,807		68,292
6% convertible senior notes		-		100,870
Other short term borrowings		-		10,665
Accrued interest and dividends payable		17,622		13,055
Current portion of accrued oil and gas reclamation costs		202,342		80,839
Current portion of accrued sulphur reclamation cost		10,719		12,145
Fair value of oil and gas derivative contracts		11,444		14,001
Current liabilities from discontinued operations		1,715		2,624
Total current liabilities		445,255		400,312
Senior secured revolving credit facility		-		274,000
5¼% convertible senior notes		74,720		115,000
11.875% senior notes		300,000		300,000
Accrued oil and gas reclamation costs		222,021		213,898
Accrued sulphur reclamation costs		9,670		9,155
Contractual postretirement obligation		5,911		6,216
Fair value of oil and gas derivative contracts		5,751		7,516
Other long-term liabilities		22,315		16,962
Total liabilities		1,085,643		1,343,059
Stockholders' equity		618,302		372,229
Total liabilities and stockholders' equity	$	1,703,945	$	1,715,288

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In Thousands, Except Per Share Amounts)
Revenues:
Oil and gas	$	282,688		$	131,018		$	946,955		$	227,381
Service		2,557			2,234			9,274			2,916
Total revenues		285,245			133,252			956,229			230,297
Costs and expenses:
Production and delivery costs		69,923			38,197			195,074			72,543
Depletion, depreciation and amortization		250,124			85,014			492,457			127,579
Exploration expenses		15,092			37,060			49,385			52,163
(Gain) loss on oil and gas derivative contracts		(80,399	)		(10,695	)		35,607			(10,695	)
General and administrative expenses		10,720			6,992			37,969			17,804
Start-up costs for Main Pass Energy Hub™		1,728			2,345			4,990			7,802
Insurance recovery		-			-			(3,391	)		-
Total costs and expenses		267,188			158,913			812,091			267,196
Operating income (loss)		18,057			(25,661	)		144,138			(36,899	)
Interest expense, net		(10,870	)		(22,887	)		(40,501	)		(34,296	)
Other income (expense), net		202			(2,457	)		(2,322	)		(876	)
Income (loss) from continuing operations before income taxes		7,389			(51,005	)		101,315			(72,071	)
Provision for income taxes		(1,284	)		-			(3,149	)		-
Income (loss) from continuing operations		6,105			(51,005	)		98,166			(72,071	)
Income (loss) from discontinued operations		(1,356	)		(1,179	)		(2,960	)		50
Net income (loss)		4,749			(52,184	)		95,206			(72,021	)
Preferred dividends, amortization of convertible preferred
stock issuance costs and inducement payments for the
early conversion of preferred stock		(10,881	)		-			(19,604	)		(1,552	)
Net income (loss) applicable to common stock	$	(6,132	)	$	(52,184	)	$	75,602		$	(73,573	)
Basic net income (loss) per share of common stock:
Continuing operations		$(0.08	)		$(1.47	)		$1.34			$(2.40	)
Discontinued operations		(0.02	)		(0.03	)		(0.05	)		0.00
Net income (loss) per share of common stock		$(0.10	)		$(1.50	)		$1.29			$(2.40	)
Diluted net income (loss) per share of common stock:
Continuing operations		$(0.08	)		$(1.47	)		$1.17			$(2.40	)
Discontinued operations		(0.02	)		(0.03	)		(0.03	)		0.00
Net income (loss) per share of common stock		$(0.10	)		$(1.50	)		$1.14			$(2.40	)
Average common shares outstanding :
Basic		64,446			34,693			58,617			30,644
Diluted		64,446			34,693			87,718			30,644

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW (Unaudited)

	Nine Months Ended
	September 30,
	2008			2007
	(In Thousands)
Cash flow from operating activities:
Net income (loss)	$	95,206		$	(72,021	)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
(Income) loss from discontinued operations		2,960			(50	)
Depletion, depreciation and amortization		492,457			127,579
Exploration drilling and related expenditures		15,692			21,663
Compensation expense associated with stock-based awards		25,546			10,905
Amortization of deferred financing costs		3,675			4,441
Unrealized loss on oil and gas derivative contracts		2,548			(10,695	)
Loss on induced conversion of convertible senior notes		2,663			-
Reclamation expenditures, net of payments by third parties		(6,500	)		(4,186	)
Increase in restricted cash		(11,364	)		-
Payment to fund terminated pension plan		(2,291	)		-
Purchase of oil and gas derivative contracts and other		83			(4,716	)
(Increase) decrease in working capital:
Accounts receivable		18,229			(72,533	)
Accounts payable and accrued liabilities		30,661			78,632
Prepaid expenses and inventories		(35,299	)		23,375
Net cash provided by continuing operations		634,266			102,394
Net cash provided by discontinued operations		1,897			673
Net cash provided by operating activities		636,163			103,067
Cash flow from investing activities:
Exploration, development and other capital expenditures		(186,904	)		(109,165	)
Acquisition of oil and gas properties		(613	)		(1,051,302	)
Proceeds from restricted investments		-			3,037
Increase in restricted investments		-			(126	)
Net cash used in continuing operations		(187,517	)		(1,157,556	)
Net cash from discontinued operations		-			-
Net cash used in investing activities		(187,517	)		(1,157,556	)
Cash flow from financing activities:
(Payments) borrowings under senior secured revolving credit
facility, net		(274,000	)		284,250
Proceeds from unsecured bridge loan facility		-			800,000
Proceeds from senior secured term loan		-			100,000
Repayment of senior secured term loan		-			(100,000	)
Financing costs		-			(31,216	)
Dividend and inducement payments on convertible preferred stock		(20,883	)		(1,121	)
Payments for induced conversion of convertible senior notes		(2,663	)		-
Proceeds from exercise of stock options and other		4,705			1,065
Net cash (used in) provided by continuing operations		(292,841	)		1,052,978
Net cash from discontinued operations		-			-
Net cash (used in) provided by financing activities		(292,841	)		1,052,978
Net increase (decrease) in cash and cash equivalents		155,805			(1,511	)
Cash and cash equivalents at beginning of year		4,830			17,830
Cash and cash equivalents at end of period	$	160,635		$	16,319

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

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McMoRan EXPLORATION CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  BASIS OF PRESENTATION

The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware corporation, are prepared in accordance with U.S. generally accepted accounting principles.  McMoRan’s consolidated financial statements include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting power 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 and Freeport Energy continues to pursue plans for a multifaceted energy services facility, including the potential development of liquefied natural gas (LNG) facilities and natural gas storage capabilities at the Main Pass Energy Hub™ (MPEH™) project.  

McMoRan’s former sulphur operations are presented as discontinued operations, and the major classes of assets and liabilities related to its former sulphur business are separately shown for the periods presented.

The accompanying unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in McMoRan’s 2007 Annual Report on Form 10-K for the year ended December 31, 2007 (2007 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 of which are of a normal recurring nature.

2.  ACQUISITION OF GULF OF MEXICO SHELF PROPERTIES

On August 6, 2007, MOXY completed the acquisition of substantially all of the proved oil and gas property interests and related assets of Newfield Exploration Company (Newfield) located on the outer continental shelf of the Gulf of Mexico for total cash consideration of $1.1 billion and the assumption of the related reclamation obligations (the 2007 oil and gas property acquisition). MOXY also acquired 50 percent of Newfield’s interests in unproved exploration leases on the outer continental shelf of the Gulf of Mexico and a majority of Newfield’s interests in the leases associated with the Treasure Island and Treasure Bay ultra deep prospects (targets below 25,000 feet). McMoRan funded this acquisition through borrowings under its variable rate senior secured revolving credit facility (credit facility) and an interim bridge loan facility.  For additional information regarding the 2007 oil and gas property acquisition and related financing activities see Notes 2 and 6 of the 2007 Form 10-K.

The allocation of the purchase price to the acquired assets and assumed liabilities is based on McMoRan’s valuation estimates.  The adjusted purchase price and purchase price allocation were finalized in the third quarter of 2008. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of the closing of the 2007 oil and gas property acquisition (August 6, 2007) (in thousands):

Cash paid for acquired assets at closing (August 6, 2007)	$	1,076,286
Estimated oil & gas reclamation costs		268,766
Net assets acquired at closing		1,345,052
Post closing adjustments		(38,645	)a
Other acquisition related costs		17,124	b
Net assets acquired	$	1,323,531

a.   Represents net cash flow from the operation of the acquired properties during the period from July 1, 2007 (effective date) to August 6, 2007 (closing date).

b.   Includes $3.5 million contingency settled in the first quarter of 2008.

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The allocation of the purchase price to the acquired properties at the date of the closing of the 2007 oil and gas property acquisition (August 6, 2007) follows (in thousands):

Accounts receivable	$	35,649
Oil and gas property, plant and equipment		1,322,819
Asset retirement obligations		(268,766	)
Other accrued liabilities		(13,416	)
Cash paid for acquired assets at closing (August 6, 2007)	$	1,076,286

The following unaudited pro forma financial information assumes MOXY acquired the properties from Newfield effective January 1, 2007 for the periods presented below (in thousands, except for per share data).

	Third Quarter			Nine Months
	2007			2007
Revenues	$	202,753		$	637,680
Operating income		11,818			68,811
Net loss		(25,695	)		(37,479	)
Basic and diluted net loss per share of common stock	$	(0.74	)	$	(1.22	)

3.  LONG-TERM DEBT

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

	September 30,		December 31,
	2008		2007
Senior secured revolving credit facility	$	-	$	274,000
11.875% senior notes due 2014		300,000		300,000
5¼% convertible senior notes due 2011		74,720		115,000
6% convertible senior notes due 2008		-		100,870
Other		-		10,665
Total debt		374,720		800,535
Less current maturities		-		(111,535	)
Long-term debt	$	374,720	$	689,000

Senior Secured Revolving Credit Facility

McMoRan’s credit facility is secured by substantially all of MOXY’s oil and gas properties and matures in August 2012.  The borrowing capacity was $500 million at September 30, 2008 and pursuant to the terms of the credit facility, it was reduced to $450 million on October 1, and will be reduced on December 31, 2008 to $400 million.

Availability under the credit facility is subject to a borrowing base, which is recalculated semi-annually each April 1 and October 1.  There were no borrowings outstanding at September 30, 2008.  McMoRan has $100 million of letters of credit issued under the credit facility to support the reclamation obligations assumed in the 2007 oil and gas property acquisition (Note 2).   At October 1, 2008, McMoRan’s unused borrowing capacity under the credit facility was $350 million.

The average interest rate on borrowings under the credit facility was 5.00 percent and 5.49 percent during the third quarter and nine months ended September 30, 2008, respectively.  The average interest rate on borrowings under the credit facility was 7.8 percent and 7.9 percent during the third quarter and nine months ended September 30, 2007, respectively.  Interest expense on the credit facility totaled $1.6 million and $10.6 million for the third quarter and nine months ended September 30, 2008, respectively, including $1.4 million and $5.1 million, respectively, of amortization expense associated with related deferred financing costs and other fees.  During the third quarter and nine months ended September 30, 2007, interest expense totaled $5.0 million and $6.0 million, respectively, including $0.6 million and $1.4 million, respectively, of amortization expense and other fees.

The credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities.  McMoRan was in compliance with these covenants at September 30, 2008.  During

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the third quarter of 2008, McMoRan entered into a second amendment to the credit facility which, among other things, (i) provides McMoRan with the ability to terminate, cancel or unwind any swap agreement associated with hedges of oil and gas prices that were previously entered into pursuant to the terms of the credit facility; and (ii) permits McMoRan to induce conversion of McMoRan’s 6¾% mandatory convertible preferred stock (6¾% preferred stock) into shares of McMoRan common stock subject to limitations on the amount of cash used to effect such inducements.  McMoRan induced the conversion of a portion of its 6¾% preferred stock in the third quarter of 2008 (Note 8).

Debt Conversion Transactions

During the nine months ended September 30, 2008, McMoRan privately negotiated transactions to induce the conversion of $39.1 million of its 6% convertible senior notes, scheduled to mature July 2, 2008 (6% notes), into approximately 2.75 million shares of its common stock.  McMoRan paid an aggregate of $1.0 million in cash to induce these conversions, which is reflected as a non-operating expense in the consolidated statements of operations.  Additionally, $61.7 million of the 6% notes were converted into approximately 4.3 million shares of McMoRan common stock in accordance with the terms of the 6% notes during the nine months ended September 30, 2008 (including the 6% notes converted into shares of common stock upon maturity on July 2, 2008).

During the nine months ended September 30, 2008, McMoRan also privately negotiated transactions to induce the conversion of $40.2 million of its 5¼% convertible senior notes due October 6, 2011 (5¼% notes) into approximately 2.4 million shares of its common stock.  McMoRan paid an aggregate $1.7 million in cash to induce these conversions, which is reflected as a non-operating expense in the consolidated statements of operations.  The 5¼% notes have a conversion price of $16.575 per share and are callable beginning on October 6, 2009 if the closing price of McMoRan’s common stock has exceeded 130% of the conversion price for at least 20 trading days in any consecutive 30-day period.

Senior Term Loan

Effective January 19, 2007, MOXY entered into a senior term loan agreement (term loan).  The term loan agreement provided for a five-year, $100 million term loan facility. Proceeds at closing, net of related fees and discounts, totaled approximately $98.0 million.  McMoRan used the net proceeds at closing to repay borrowings then outstanding at that time under its previous revolving credit facility.   At the closing of the 2007 oil and gas property acquisition, McMoRan repaid this loan. See Note 6 of the 2007 Form 10-K for additional information regarding repayment of the term loan.

Fair Value of Debt

The fair value of the 5¼% notes and 11.875% senior notes due 2014 (11.875% senior notes) are determined at each reporting period using inputs based upon quoted prices for such instruments in active markets.  As of September 30, 2008, the estimated fair value of the 5¼% notes and 11.875% senior notes was $105.5 million and $288.0 million, respectively.  The fair value of the credit facility, which has a variable interest rate that floats with changes in market interest rates, approximates the carrying value.

4.   EARNINGS PER SHARE

Basic net income (loss) per share of common stock has been calculated by dividing the net income (loss) applicable to continuing operations, net income (loss) from discontinued operations and net income (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 income (loss) applicable to continuing operations includes preferred stock dividends and inducement payments made for the early conversion of the 6¾% preferred stock.

The table below reconciles McMoRan’s basic net income per share to its diluted net income per share for the nine months ended September 30, 2008 (amounts in thousands, except per share data):

8

Basic net income from continuing operations	$	78,562
Add:  Preferred dividends from assumed conversion of  6¾% mandatory
convertible preferred stock and inducement payments		19,604
Add:  Net interest from assumed conversion of 6% notes		1,514
Add:  Net interest from assumed conversion of 5¼% notes		3,484
Diluted net income from continuing operations		103,164
Loss from discontinued operations		(2,960	)
Diluted net income applicable to common stock	$	100,204
Weighted average common shares outstanding for purpose of calculating
basic net income per share		58,617
Assumed exercise of dilutive stock options a, b		2,183
Assumed exercise of stock warrants a, c		368
Assumed conversion of 6¾% mandatory convertible preferred stock d		17,187
Assumed conversion of 6% notes e		3,520
Assumed conversion of 5¼% notes f		5,843
Weighted average common shares outstanding
for purposes of calculating diluted net income per share		87,718
Diluted net income per share from continuing operations		$1.17
Diluted net loss per share from discontinued operations		(0.03	)
Diluted net income per share		$1.14

McMoRan had a net loss from continuing operations for the third quarter ended September 30, 2008 and the third quarter and nine months ended September 30, 2007.  Accordingly, McMoRan’s diluted per share calculation for these periods is the same as its basic net loss per share calculation because it excludes the assumed exercise of stock options and stock warrants whose exercise prices were less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of the 6% notes, 5¼% notes, 6¾% preferred stock and 5% mandatorily redeemable convertible preferred stock (5% preferred stock). The excluded share amounts for the third quarter ended September 30, 2008 and the third quarter and nine months ended September 30, 2007 are summarized below (in thousands):

	Third	Third	Nine
	Quarter	Quarter	Months
	2008	2007
Stock options a, b	2,947	709	663
Stock warrants a, c	20	1,550	1,538
Assumed conversion of 6¾% mandatory convertible preferred
stock d	16,899	-	-
5% mandatorily redeemable convertible preferred stock g	-	-	-
6% convertible senior notes e	66	7,079	7,079
5¼% convertible senior notes f	4,508	6,938	6,938

a.   McMoRan uses the treasury stock method to determine total shares related to in-the-money stock options and stock warrants for purposes of its diluted earnings per share calculation.

b.   Represents stock options with an exercise price less than the average market price for McMoRan’s common stock for the periods presented.

c.   Includes in-the-money stock warrants issued to K1 USA Energy Production Corporation (K1) in December 2002 (1.74 million shares) and September 2003 (0.76 million shares).  The warrants were exercisable for McMoRan common stock at any time over their respective five-year terms at an exercise price of $5.25 per share.  In December 2007, K1 exercised the stock warrant for 1.74

9

million common shares.  In June 2008, K1 exercised the stock warrant for 0.76 million common shares in a cashless transaction and received 0.64 million common shares.  See Note 5 of the 2007 Form 10-K for additional information regarding the warrants.

d.   In the third quarter of 2008, McMoRan induced conversion of approximately $99.0 million of its 6¾% preferred stock.  See Note 8 of the 2007 Form 10-K for information regarding McMoRan’s 6¾% preferred stock.

e.   The 6% notes, issued in July 2003, were convertible at the option of the holder at any time prior to their maturity on July 2, 2008 into shares of McMoRan common stock at a conversion price of $14.25 per share.  Net interest expense on the 6% notes totaled zero and $1.6 million during the third quarter of 2008 and 2007, respectively, and $1.5 million and $4.7 million for the nine month periods ended September 30, 2008 and 2007, respectively.  On July 2, 2008, the remaining holders converted the 6% notes into shares of McMoRan common stock.  Additional information regarding the 6% notes is discussed in Note 6 of the 2007 Form 10-K.

f.   The 5¼% notes, issued in October 2004, are convertible at the option of the holder at any time prior to their maturity on October 6, 2011 into shares of McMoRan common stock at a conversion price of $16.575 per share.   Net interest expense on the 5¼% notes totaled $1.0 million and $1.5 million during the third quarter of 2008 and 2007, respectively, and $3.5 million and $4.4 million for the nine month periods ended September 30, 2008 and 2007, respectively. Additional information regarding the 5¼% notes is discussed in Note 6 of the 2007 Form 10-K.

g.   All of the remaining shares of McMoRan’s 5% preferred stock were converted into approximately 6.2 million shares of McMoRan common stock in the second quarter of 2007.  The conversion of the 5% preferred stock, which occurred in June 2007, did not have a material impact on the average shares outstanding for the third quarter and nine months ended September 30, 2007.  See Note 8 of the 2007 Form 10-K for additional information regarding the 5% preferred stock.

Outstanding stock options excluded from the computation of diluted net income (loss) per share of common stock because their exercise prices were greater than the average market price of the common stock during the third quarter and nine months ended September 30, 2008 and 2007 are as follows:

	Third Quarter				Nine Months
	2008		2007		2008		2007
Outstanding options (in thousands)		40		5,378		45		5,378
Average exercise price	$	31.92	$	17.38	$	31.08	$	17.38

5.   DERIVATIVE CONTRACTS

In connection with the closing of the 2007 oil and gas property acquisition (Note 2) and related financing, MOXY entered into derivative contracts for a portion of the anticipated production from its proved developed producing oil and gas properties at the time of the acquisition for the years 2008 through 2010. In the third quarter of 2008, McMoRan entered into a second amendment to the credit facility which, among other things, provides it with the option to terminate outstanding swap agreements (Note 3).  Excluding the put options, McMoRan has a total of 12.6 Bcf of natural gas and 0.6 million barrels of oil hedged through 2010, representing less than 5 percent of estimated proved reserves as of September 30, 2008. At September 30, 2008, McMoRan’s remaining outstanding oil and gas derivative contracts were as follows:

	Natural Gas Positions (million MMbtu)
	Open Swap Positions a			Put Options b
		Average			Average
	Volumes	Swap Price d		Volumes	Floor d
2008c	2.7	$	9.16	1.5	$	6.00
2009	7.3	$	8.97	3.2	$	6.00
2010	2.6	$	8.63	1.2	$	6.00

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	Oil Positions (thousand bbls)
	Open Swap Positions a			Put Options b
		Average			Average
	Volumes	Swap Price e		Volumes	Floor e
2008c	120	$	72.30	66	$	50.00
2009	322	$	71.82	125	$	50.00
2010	118	$	70.89	50	$	50.00

a.   Covering periods January-June and November-December of the respective years.  Contracts for the January-June 2008 period have been settled, resulting in realized losses of $31.2 million for the nine months ended September 30, 2008.

b.   Covering periods July-October of the respective years.

c.   For the fourth quarter.

d.   Price per MMbtu of natural gas.

e.   Price per barrel of oil.

Because these oil and gas derivative contracts were not designated as hedges for accounting purposes, changes in the related fair values are recognized immediately in McMoRan’s operating results at each reporting period.  During the third quarter and nine months ended September 30, 2008 and 2007, McMoRan’s realized and unrealized (gains) losses on these contracts were as follows (in thousands):

	Third Quarter
	2008			2007
Realized loss
Gas puts	$	1,579		$	-
Oil puts		274			-
Gas swaps		-			-
Oil swaps		3			-
Total realized loss		1,856			-
Unrealized (gain) loss
Gas puts		(2,356	)		170
Oil puts		(357	)		367
Gas swaps		(58,752	)		(14,489	)
Oil swaps		(20,790	)		3,257
Total unrealized gain		(82,255	)		(10,695	)
(Gain) loss on oil and gas derivative
contracts	$	(80,399	)	$	(10,695	)

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	Nine Months
	2008			2007
Realized loss
Gas puts	$	1,579		$	-
Oil puts		274			-
Gas swaps		10,777			-
Oil swaps		20,429			-
Total realized loss		33,059			-
Unrealized (gain) loss
Gas puts		(32	)		170
Oil puts		(304	)		367
Gas swaps		7,048			(14,489	)
Oil swaps		(4,164	)		3,257
Total unrealized (gain) loss		2,548			(10,695	)
(Gain) loss on oil and gas derivative
contracts	$	35,607		$	(10,695	)

The original cost of the put options was $4.6 million.  There was no initial cost for entering into the swap contracts.  The derivative contracts are reported at fair value on McMoRan’s balance sheets.  McMoRan adopted SFAS 157 on January 1, 2008.  The fair value of McMoRan’s swaps and puts are valued based on transaction counterparty acknowledgements and corroborated based on quoted market prices.  McMoRan has classified its derivative instruments as Level 2 inputs (Note 9).  The following table provides fair value measurement information as of September 30, 2008 and December 31, 2007 (in thousands).

	September 30, 2008
	Puts				Swaps
	Gas		Oil		Gas			Oil			Total
Current assets	$	485	$	49	$	10,501		$	-		$	11,035
Other assets		423		66		693			-			1,182
Current liabilities		-		-		-			(11,444	)		(11,444	)
Other long-term liabilities		-		-		(577	)		(5,174	)		(5,751	)
Fair value of contracts	$	908	$	115	$	10,617		$	(16,618	)	$	(4,978	)

	December 31, 2007
	Puts				Swaps
	Gas		Oil		Gas			Oil			Total
Current assets	$	1,350	$	4	$	15,269		$	-		$	16,623
Other assets		1,105		81		3,131			-			4,317
Current liabilities		-		-		-			(14,001	)		(14,001	)
Other long-term liabilities		-		-		(735	)		(6,781	)		(7,516	)
Fair value of contracts	$	2,455	$	85	$	17,665		$	(20,782	)	$	(577	)

6.  INCOME TAXES

As of January 1, 2008 and September 30, 2008, McMoRan had approximately $264.6 million and $232.9 million, respectively, of unrecognized tax benefits relating to its reported net losses and other temporary differences from operations.  McMoRan recorded a full valuation allowance on these deferred tax assets (see Note 11 of the 2007 Form 10-K).  McMoRan’s effective tax rate will be reduced in future periods to the extent these deferred tax assets are recognized. McMoRan will continue to assess whether or not deferred tax assets can be recognized based on operating results in future periods. Internal Revenue Code provisions limit the application of alternative minimum tax net operating losses to ninety percent of defined alternative minimum taxable income, and the tax provisions of $1.3 million and $3.1 million for the third quarter and nine months ended September 30, 2008, respectively, reflect this limitation.  No benefit for resulting alternative minimum tax credits has been recognized in McMoRan’s statement of operations for the third quarter or nine months ended September 30, 2008. Federal tax regulations impose additional limitations on the utilization of net operating loss carry forwards from prior periods when a defined level of

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change in the stock ownership of certain shareholders is exceeded. Through September 30, 2008, no such change in ownership was determined.  McMoRan continues to monitor stock ownership changes under the guidance of these provisions.  Should an ownership change be determined or considered probable of occurring, McMoRan will include the impact of such change in the period that determination is made.

Interest or penalties associated with income taxes are recorded as components of the provision for income taxes, although no such amounts have been recognized in the accompanying financial statements.  Currently, McMoRan’s major taxing jurisdictions are the United States (federal) and Louisiana.  McMoRan recently added producing properties in Texas.  Tax periods open to audit for McMoRan include federal income tax returns subsequent to 2004 and Louisiana income tax returns subsequent to 2003.

7. OIL AND GAS ACTIVITIES

Exploration and Operations.

Since 2004, McMoRan has participated in 17 discoveries on 33 prospects that have been drilled and fully evaluated.   McMoRan has investments in six in-progress or unevaluated wells totaling $96.7 million at September 30, 2008, including $22.7 million for the Blueberry Hill well,  $15.4 million for the Mound Point South well, $2.0 million for the Tom Sauk well (each located at Louisiana State Lease 340), $29.5 million for the JB Mountain Deep well at South Marsh Island Block 224, $23.5 million for the South Timbalier Block 168 No. 1 well and $3.6 million for the Northeast Belle Isle well in St. Mary Parish, Louisiana.

McMoRan’s investments in Blueberry Hill, JB Mountain Deep and Mound Point South have been capitalized for a period in excess of one year following the completion of their initial drilling operations.  The Blueberry Hill well encountered four potentially productive zones below 22,200 feet in February 2005 and has been assigned proved reserves by an independent petroleum engineering firm. Initial completion activities were undertaken in the first half of 2007; however, the well was unable to produce because of a blockage above the perforated interval.  A sidetrack well was planned for late 2008; however, as a result of the 2008 Gulf of Mexico hurricane activity, the timing of the sidetrack has been delayed.

The JB Mountain Deep well reached its total depth of 24,600 feet in April 2006.  Wireline logs indicated potential hydrocarbon bearing sands at two depths.   A protective liner was set and the well was temporarily abandoned.  McMoRan will incorporate information obtained from the Blueberry Hill and the Hurricane Deep wells at South Marsh Island Block 217, which commenced production in January 2008, in the future plans for the JB Mountain Deep well.

The Mound Point South well was drilled to a total measured depth of 21,065 feet in September 2007.  Based on wireline logs, the well encountered potential hydrocarbon bearing sands; however, the well was temporarily abandoned in September 2007.  Completion of the Mound Point South well was deferred pending results of a similar well, the Tom Sauk well, which commenced drilling in third quarter 2008.

McMoRan recently completed negotiations to participate in the Ammazzo exploration prospect located on South Marsh Island Block 251 which is within a common depositional basin together with the Blueberry Hill, JB Mountain Deep, Mound Point South and Tom Sauk wells.  The areas surrounding these wells, the Tiger Shoal/Mound Point areas, demonstrate similar geologic settings and target the same deep Miocene sands.  McMoRan has performed more extensive geologic and geophysical evaluations of this basin over the past several months and believes that the results of the Tom Sauk and Ammazzo wells will provide additional data to determine the best techniques for the continued development of the Blueberry Hill, JB Mountain Deep and Mound Point South wells.  The Tom Sauk well is currently drilling below 12,800 feet towards a proposed total depth of 19,000 feet and the Ammazzo well is expected to commence drilling in November 2008.

In August 2008, the drilling results for the Mound Point East well at Louisiana State Lease 340 were evaluated and deemed to be non-productive.  As a result, the well was plugged and abandoned. McMoRan charged $10.8 million of costs incurred for drilling the well through June 30, 2008 to exploration expense in its second quarter 2008 results.   Approximately $4.3 million of costs incurred subsequent to June 30, 2008 were charged to exploration expense in the third quarter of 2008.

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The King of the Hill well commenced production in August 2006 from the same reservoir as other productive wells in adjacent lease blocks. During 2007 the well began producing significant amounts of water and multiple attempts to establish production were unsuccessful.  In September 2008, McMoRan charged $10.8 million to depreciation, depletion and amortization expense to write off its remaining investment in the well.

In the second quarter of 2008, McMoRan recorded a $7.4 million charge to depletion, depreciation and amortization expense to write off its remaining investment in Ship Shoal Block 139 and West Cameron Block 176 as a result of the wells producing significant amounts of water and remedial operations being unable to restore production.

If any in-progress or unproved property is determined to be non-productive or no longer meets the capitalization requirements under applicable accounting rules, McMoRan may be required to write down its investment in such properties to their net realizable value.  See Note 1 of the 2007 Form 10-K for additional information regarding the periodic assessment of potential impairments to McMoRan’s properties.

The determination of oil and gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.  In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production.  Subsequent evaluation of the same reserves may result in variations in estimated reserves and related estimates of future cash flows. These variations may be substantial.  If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required.  For more information regarding the risks associated with the reserve estimation process see Item 1A. “Risk Factors” located in McMoRan’s 2007 Form 10-K.

2008 Hurricane Activity.

Hurricanes Gustav and Ike impacted Gulf of Mexico operations prior to making landfall on the Louisiana and Texas coasts on September 1, 2008 and September 13, 2008, respectively.  There was no significant damage to McMoRan’s properties resulting from Hurricane Gustav.  Assessments following Hurricane Ike identified several platforms, comprising approximately three percent of production and two percent of reserves, with significant structural damage.  Substantially all of McMoRan’s remaining production facilities are capable of resuming production pending restoration of downstream pipelines and facilities operated by third parties.  Drilling rigs used in McMoRan’s exploration and development activities sustained no significant damage in the storms and operations have resumed.

McMoRan recorded impairment charges of $21.9 million in the third quarter of 2008 to eliminate the carrying value of Ewing Banks Block 947 and South Marsh Island Block 49F after McMoRan concluded that the reserves associated with these properties would not be recoverable due to significant structural damage caused by Hurricane Ike.  Additionally, McMoRan recorded reclamation charges of $124.4 million in the third quarter of 2008 to record the additional reclamation costs for damaged properties and the acceleration of the timing of when these costs are expected to be incurred.  McMoRan also recorded $6.3 million in production and delivery costs related to damage assessment and repairs during the third quarter of 2008.  McMoRan expects to realize a substantial recovery under its insurance program for hurricane related costs, which are expected to be incurred over several years.  Insurance recovery will be recorded as income in McMoRan’s future financial results as claims are settled with insurers.

Accrued Reclamation Obligations.

McMoRan follows SFAS No. 143 “Accounting for Asset Retirement Obligations” in determining amounts to record for the fair value of obligations associated with the removal of long-lived assets in the period they are incurred.  For more information regarding McMoRan’s accounting for asset retirement obligations see Notes 1 and 13 of McMoRan’s 2007 Form 10-K.   A summary of changes in McMoRan’s consolidated

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discounted asset retirement obligations (including both current and long-term obligations) since December 31, 2007 follows (in thousands):

	Oil and
	Natural Gas			Sulphur
Asset retirement obligation at beginning of year	$	294,737		$	21,300
Liabilities settled		(24,487	)a		(1,560	)
Accretion expense		22,371			649
Reclamation costs assumed from third parties		2,859	b		-
Incurred liabilities		2,185			-
Revision for changes in estimates		126,698	c		-
Asset retirement obligations at September 30, 2008	$	424,363		$	20,389

a.  Includes $15.1 million of costs included in accounts payable at September 30, 2008 for completed work.

b.  Represents reimbursement paid to McMoRan for future reclamation expenditures.  McMoRan has assumed the third parties’ reclamation liability in these specific fields.

c.  Primarily represents estimated future abandonment costs associated with damaged structures and well abandonment related to Hurricane Ike.

Inventory.

Product inventories totaled $0.7 million at September 30, 2008 and $1.5 million at December 31, 2007, consisting entirely of oil associated with operations at Main Pass Block 299.  Materials and supplies inventory totaling $32.5 million at September 30, 2008 and $10.0 million at December 31, 2007 represents the cost of supplies to be used in McMoRan’s drilling activities, primarily drilling pipe and tubulars. These costs will be partially reimbursed by third party participants in wells supplied with these materials.  McMoRan’s inventories are stated at the lower of weighted average cost or market.  There have been no required adjustments to reduce the carrying value of McMoRan’s inventories for any of the periods presented.

8. OTHER MATTERS

6¾% Mandatory Convertible Preferred Stock.

In November 2007, McMoRan completed a public offering of 2.59 million shares of 6¾% preferred stock.  In September 2008, McMoRan agreed in a privately negotiated transaction to induce conversion of approximately 990,000 shares of its 6¾% preferred stock, with a liquidation preference of approximately $99 million, into approximately 6.7 million shares of McMoRan common stock (based on the minimum conversion rate of 6.7204 shares of common stock for each share of 6¾% preferred stock). McMoRan paid an aggregate $7.4 million in cash to the holders of these shares to induce the conversion of this 6¾% preferred stock, which is recorded as a charge to preferred dividends in the third quarter of 2008.  Preferred dividend payment savings related to this transaction approximate $15 million through the November 2010 mandatory conversion date of the securities.  See Note 8 of the 2007 Form 10-K for information regarding McMoRan’s 6¾% preferred stock.

Interest Cost.

Interest expense capitalized by McMoRan totaled $1.0 million in the third quarter of 2008 and $3.8 million for the nine months ended September 30, 2008.  Capitalized interest totaled $2.0 million in the third quarter of 2007 and $4.5 million for the nine months ended September 30, 2007.

Pension Plan.

During 2000, McMoRan elected to terminate its defined benefit plan (Pension Plan).  McMoRan received notification dated April 14, 2008 that the Internal Revenue Service approved the plan’s termination.  McMoRan funded the approximate $2.3 million shortfall between the plan’s obligations and the underlying plan assets in August 2008.  McMoRan also provides certain health care and life insurance benefits (Other Benefits) to retired employees.  For more information regarding these Pension and Other Benefit plans see Note 10 of the 2007 Form 10-K.  The components of McMoRan’s net periodic expense associated with McMoRan’s Pension Plan for the third quarter and nine months ended September 30, 2008 and 2007 follows (in thousands):

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	Third Quarter						Nine Months
	2008			2007			2008			2007
Interest cost	$	81		$	97		$	65		$	126
Service cost		-			-						-
(Return) loss on plan assets		(5	)		(25	)		(23	)		(72	)
Change in plan payout assumptions		-			-			-			-
Net periodic benefit expense	$	76		$	72		$	42		$	54

The components of net periodic expense associated with McMoRan’s Other Benefits plan for the third quarter and nine months ended September 30, 2008 and 2007 follows (in thousands):

	Third Quarter					Nine Months
	2008			2007		2008			2007
Interest cost	$	84		$	86	$	251		$	258
Service cost		7			5		20			14
Amortization of prior service costs
and actuarial gains		(1	)		14		(4	)		42
Net periodic benefit expense	$	90		$	105	$	267		$	314

Stock-Based Compensation.

For information regarding McMoRan’s accounting for stock-based awards, see Note 1 of the 2007 Form 10-K.  Compensation cost charged to expense for stock-based awards for the third quarter and nine months ended September 30, 2008 and 2007 follows (in thousands).

	Third Quarter				Nine Months
	2008		2007		2008			2007
Cost of options awarded to employees (including
directors)	$	4,329	$	2,007	$	24,389	a	$	10,382	a
Cost of options awarded to non-employees and advisory
directors		261		133		991			492
Cost of restricted stock units		81		25		166			31
Total compensation cost	$	4,671	$	2,165	$	25,546		$	10,905

a.   Includes compensation charges associated with immediately vested stock options totaling $16.2 million and $4.4 million, respectively, for the nine months ended September 30, 2008 and 2007.  These compensation costs include the stock options granted to McMoRan’s Co-Chairmen in lieu of receiving any cash compensation during the respective periods and the compensation costs related to stock options granted to retiree-eligible employees, which resulted in one-year’s compensation expense being immediately recognized at the effective date of the stock option grant.

McMoRan had a minimal amount of stock options available for grant to its employees at December 31, 2007.  On January 28, 2008, McMoRan’s Board of Directors granted a total of 1,654,500 stock options subject to shareholder approval of the 2008 Stock Incentive Plan (2008 Plan).  The stock options were granted to its employees at an exercise price of $15.04 per share (the closing market price on that date), including immediately exercisable options for an aggregate of 445,000 shares.  Options representing 400,000 of these 445,000 shares were issued to McMoRan’s Co-Chairmen in lieu of cash compensation in 2008.  Stock options under the 2008 Plan and the 2004 Director Compensation Plan were also granted to non-employee directors and advisory directors effective June 1, 2008.  Approval of the 2008 Plan was received at the annual shareholders’ meeting held on June 5, 2008 when the closing market price was $34.40 per share. Accordingly, the related fair values of such grants were charged to expense beginning in the second quarter 2008 in accordance with SFAS 123R.  The weighted average option value of the 1,699,500 options granted during the nine months ended September 30, 2008 was $24.95.  See Note 10 of the 2007 Form 10-K.

As of September 30, 2008, total compensation cost related to nonvested, approved stock option awards not yet recognized in earnings was approximately $28.6 million, which is expected to be recognized over a weighted average period of one year.

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Comprehensive Income (loss).

McMoRan’s comprehensive income (loss) for the third quarter and nine months ended September 30, 2008 and 2007 is shown below (in thousands).

	Third Quarter						Nine Months
	2008			2007			2008			2007
Net income (loss)	$	(6,132	)	$	(52,184	)	$	75,602		$	(73,573	)
Other comprehensive income (loss)
Amortization of previously unrecognized pension
components, net		(1	)		14			(4	)		42
Comprehensive income (loss)	$	(6,133	)	$	(52,170	)	$	75,598		$	(73,531	)

9.  NEW ACCOUNTING STANDARDS

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), clarifies the definition of fair value within that framework, and expands disclosures about the use of fair value measurements. In many of its pronouncements, the FASB has previously concluded that fair value information is relevant to the users of financial statements and has required (or permitted) fair value as a measurement objective. However, prior to the issuance of this statement, there was limited guidance for applying the fair value measurement objective in GAAP. This statement does not require any new fair value measurements in GAAP.  McMoRan adopted SFAS No. 157 on January 1, 2008 with no material changes to its financial position or results of operations.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The fair value hierarchy consists of three broad levels:

·   Level 1:  valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority;

·   Level 2:  valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability;

·   Level 3:  valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.

The only financial instruments reported at fair value are McMoRan's derivative instruments, which are discussed in Note 5.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities.” SFAS No. 159 permits entities to choose to measure certain financial instruments and certain other items at fair value. McMoRan adopted SFAS No. 159 on January 1, 2008 with no impact to its financial statements.

In December 2007, the FASB issued SFAS No. 141(R), “Applying the Acquisition Method.”  SFAS 141(R) requires an acquirer to recognize 100 percent of the fair values of acquired assets, with limited exceptions, even if the acquirer has not acquired 100 percent of its target.  Additionally, contingent consideration arrangements and preacquisition contingencies will be measured at fair value on the acquisition date and included in the basis of the purchase price.  Transaction costs will now be expensed as incurred and not considered as part of the fair value of the acquisition; however, acquired research and development will no longer be expensed at acquisition, but instead will be capitalized as an indefinite-lived intangible asset.  SFAS 141(R) is effective for fiscal years beginning after December 15, 2008 and early adoption is not allowed. McMoRan’s accounting for its 2007 oil and gas property acquisition is not affected by this new standard.

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In December 2007, the FASB issued SFAS No. 160, “Accounting for Noncontrolling Interests.”  SFAS 160 clarifies the classification of noncontrolling interests in the consolidated balance sheet and the accounting for and reporting of transactions between the reporting entity and holders of these noncontrolling interests.  Under SFAS 160, noncontrolling interests (minority interests) are to be considered equity transactions and reflected accordingly in the balance sheet and related statement of cash flow.  SFAS 160 will require separate disclosure on the face of the income statement distinguishing between the controlling and noncontrolling interests. SFAS 160 is effective for fiscal years beginning after December 15, 2008 and early adoption is not permitted. McMoRan does not believe that SFAS No. 160 will have a material impact on its financial statements.

In March 2008, the FASB issued FAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133”.  SFAS No. 161 requires enhanced disclosure related to derivatives and hedging activities and thereby seeks to improve the transparency of financial reporting. Under FAS No. 161, entities are required to provide enhanced disclosures relating to: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedge items are accounted for under FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS No. 133”), and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 must be applied prospectively to all derivative instruments and non-derivative instruments that are designated and qualify as hedging instruments and related hedged items accounted for under SFAS No. 133 for all financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. McMoRan is currently evaluating the impact that SFAS No. 161 will have on its financial statements.

In May 2008, the FASB issued FASB Staff Position APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).”   This FASB Staff Position requires the issuer of certain convertible debt instruments that may be settled in cash (or other assets) on conversion to separately account for the liability (debt) and equity (conversion option) components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate.  This will require the accretion of the resulting discount on the liability component of the convertible debt, which will result in additional interest expense based on McMoRan’s nonconvertible debt borrowing rate.  This FASB Staff position is effective for fiscal years beginning after December 15, 2008 and must be applied retrospectively for all periods presented. McMoRan is currently evaluating the impact that this FASB Staff Position will have on its 5¼% notes and related interest expense.

10.  GUARANTOR FINANCIAL STATEMENTS

MOXY is an unconditional guarantor of McMoRan’s 11.875% senior notes.  See Notes 6 and 15 of the 2007 Form 10-K for additional information regarding the 11.875% senior notes and MOXY’s related guarantee.

               The following unaudited condensed 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, 2008 and December 31, 2007 and the related condensed consolidating statements of operations and cash flow for the third quarter and nine months ended September 30, 2008 and 2007, which should be read in conjunction with the Notes to these unaudited condensed consolidated financial statements:

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TABLE OF CONTENTS

CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)

September 30, 2008

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan
	(in Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	19	$	160,590	$	26		$	-		$	160,635
Accounts receivable		-		115,712		-			-			115,712
Inventories		-		33,153		-			-			33,153
Prepaid expenses		17,757		1,414		-			-			19,171
Fair value of oil and gas derivative
contracts		-		11,035		-			-			11,035
Current assets from discontinued
operations		-		-		3,175			-			3,175
Total current assets		17,776		321,904		3,201			-			342,881
Property, plant and equipment, net		-		1,316,819		31			-			1,316,850
Sulphur business assets, net		-		-		339			-			339
Investment in subsidiaries		1,137,447		-		-			(1,137,447	)		-
Amounts due from affiliates		-		146,605		(1,054	)		(145,551	)		-
Deferred financing costs and other
assets		11,526		32,222		127			-			43,875
Total assets	$	1,166,749	$	1,817,550	$	2,644		$	(1,282,998	)	$	1,703,945
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		255		104,960		391			-		$	105,606
Accrued liabilities		1,270		93,754		783			-			95,807
Current portion of oil and gas
accrued reclamation costs		-		202,342		-			-			202,342
Other current liabilities		16,722		12,344		-			-			29,066
Current liabilities from discontinued
operations		-		-		12,434			-			12,434
Total current liabilities		18,247		413,400		13,608			-			445,255
Long-term debt		374,720		-		-			-			374,720
Amounts due to affiliates		145,551		-		-			(145,551	)		-
Accrued oil and gas reclamation costs		-		222,021		-			-			222,021
Accrued sulphur reclamation costs		-		-		9,670			-			9,670
Other long-term liabilities		9,929		15,054		8,994			-			33,977
Total liabilities		548,447		650,475		32,272			(145,551	)		1,085,643
Commitments and contingencies
Stockholders’ equity (deficit)		618,302		1,167,075		(29,628	)		(1,137,447	)		618,302
Total liabilities and stockholders’ equity	$	1,166,749	$	1,817,550	$	2,644		$	(1,282,998	)	$	1,703,945

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CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2007

					Freeport
	McMoRan		MOXY		Energy			Eliminations			McMoRan
	(in Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	143	$	3,446	$	1,241		$	-		$	4,830
Accounts receivable		885		127,805		-			-			128,690
Inventories		-		11,507		-			-			11,507
Prepaid expenses		12,833		1,498		-			-			14,331
Fair value of derivative contracts		-		16,623		-			-			16,623
Current assets from discontinued
operations		-		-		3,029			-			3,029
Total current assets		13,861		160,879		4,270			-			179,010
Property, plant and equipment, net		-		1,503,328		31			-			1,503,359
Sulphur business assets, net		-		-		349			-			349
Investment in subsidiaries		971,176		-		-			(971,176	)		-
Amounts due from affiliates		-		68,341		5,987			(74,328	)		-
Deferred financing costs and other
Assets		14,135		18,308		127			-			32,570
Total assets	$	999,172	$	1,750,856	$	10,764		$	(1,045,504	)	$	1,715,288
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		222		97,300		299			-		$	97,821
Accrued liabilities		2,110		65,006		1,176			-			68,292
Current portion of debt		111,535		-		-			-			111,535
Current portion of oil and gas
accrued reclamation costs		-		80,839		-			-			80,839
Other current liabilities		11,723		15,333		-			-			27,056
Current liabilities from discontinued
operations		-		-		14,769			-			14,769
Total current liabilities		125,590		258,478		16,244			-			400,312
Long-term debt		415,000		274,000		-			-			689,000
Amounts due to affiliates		74,328		-		-			(74,328	)		-
Accrued oil and gas reclamation costs		-		213,898		-			-			213,898
Accrued sulphur reclamation costs		-		-		9,155						9,155
Other long-term liabilities		12,025		9,245		9,424			-			30,694
Total liabilities		626,943		755,621		34,823			(74,328	)		1,343,059
Commitments and contingencies
Stockholders’ equity (deficit)		372,229		995,235		(24,059	)		(971,176	)		372,229
Total liabilities and stockholders’ equity	$	999,172	$	1,750,856	$	10,764		$	(1,045,504	)	$	1,715,288

20

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Third Quarter Ended September 30, 2008

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
	(In Thousands)
Revenues:
Oil and gas	$	-		$	282,688		$	-		$	-		$	282,688
Service		-			2,557			-			-			2,557
Total revenues		-			285,245			-			-			285,245
Costs and expenses:
Production and delivery costs		-			69,936			(13	)		-			69,923
Depreciation and amortization		-			250,124			-			-			250,124
Exploration expenses		-			15,092			-			-			15,092
Gain on oil and gas derivative contracts		-			(80,399	)		-			-			(80,399	)
General and administrative expenses		2,049			8,605			66			-			10,720
Start-up costs for Main Pass
Energy Hub™		-			-			1,728			-			1,728
Insurance recovery		-			-			-			-			-
Total costs and expenses		2,049			263,358			1,781			-			267,188
Operating income (loss)		(2,049	)		21,887			(1,781	)		-			18,057
Interest expense		(10,284	)		(586	)		-			-			(10,870	)
Equity in earnings of consolidated
subsidiaries		18,362			-			-			(18,362	)		-
Other income (expense), net		4			198			-			-			202
Income (loss) from continuing operations
before income taxes		6,033			21,499			(1,781	)		(18,362	)		7,389
Provision for income taxes		(1,284	)		-			-			-			(1,284	)
Income (loss) from continuing operations		4,749			21,499			(1,781	)		(18,362	)		6,105
Loss from discontinued operations		-			-			(1,356	)		-			(1,356	)
Net income (loss)		4,749			21,499			(3,137	)		(18,362	)		4,749
Preferred dividends, amortization
of issuance costs and inducement
payments for early conversion of
preferred stock		(10,881	)		-			-			-			(10,881	)
Net income (loss) applicable to
common stock	$	(6,132	)	$	21,499		$	(3,137	)	$	(18,362	)	$	(6,132	)

21

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Nine Months Ended September 30, 2008

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
	(In Thousands)
Revenues:
Oil and gas	$	-		$	946,955		$	-		$	-		$	946,955
Service		-			9,274			-			-			9,274
Total revenues		-			956,229			-			-			956,229
Costs and expenses:
Production and delivery costs		-			195,113			(39	)		-			195,074
Depreciation and amortization		-			492,457			-			-			492,457
Exploration expenses		-			49,385			-			-			49,385
Loss on oil and gas derivative contracts		-			35,607			-			-			35,607
General and administrative expenses		5,712			32,020			237			-			37,969
Start-up costs for Main Pass
Energy Hub™		-			-			4,990			-			4,990
Insurance recovery		-			(3,391	)		-			-			(3,391	)
Total costs and expenses		5,712			801,191			5,188			-			812,091
Operating income (loss)		(5,712	)		155,038			(5,188	)		-			144,138
Interest expense		(33,422	)		(7,079	)		-			-			(40,501	)
Equity in earnings of consolidated														-
subsidiaries		140,122			-			-			(140,122	)		-
Other income (expense), net		(2,633	)		311			-			-			(2,322	)
Income (loss) from continuing operations
before income taxes		98,355			148,270			(5,188	)		(140,122	)		101,315
Provision for income taxes		(3,149	)		-			-			-			(3,149	)
Income (loss) from continuing operations		95,206			148,270			(5,188	)		(140,122	)		98,166
Loss from discontinued operations		-			-			(2,960	)		-			(2,960	)
Net income (loss)		95,206			148,270			(8,148	)		(140,122	)		95,206
Preferred dividends, amortization
of issuance costs and inducement
payments for early conversion of
preferred stock		(19,604	)		-			-			-			(19,604	)
Net income (loss) applicable to
common stock	$	75,602		$	148,270		$	(8,148	)	$	(140,122	)	$	75,602

22

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Third Quarter Ended September 30, 2007

							Freeport					Consolidated
	Parent			MOXY			Energy			Eliminations		McMoRan
	(In Thousands)
Revenues:
Oil and gas	$	-		$	131,018		$	-		$	-	$	131,018
Service		-			2,234			-			-		2,234
Total revenues		-			133,252			-			-		133,252
Costs and expenses:
Production and delivery costs		-			38,209			(12	)		-		38,197
Depreciation and amortization		-			85,014			-			-		85,014
Exploration expenses		-			37,060			-			-		37,060
General and administrative expenses		1,147			5,789			56			-		6,992
Gain on oil and gas derivative contracts		-			(10,695	)		-			-		(10,695	)
Start-up costs for Main Pass
Energy Hub™		-			-			2,345			-		2,345
Total costs and expenses		1,147			155,377			2,389			-		158,913
Operating loss		(1,147	)		(22,125	)		(2,389	)		-		(25,661	)
Interest expense		(16,351	)		(6,536	)		-			-		(22,887	)
Equity in losses of
consolidated subsidiaries		(35,047	)		-			-			35,047		-
Other income, net		361			(2,818	)		-			-		(2,457	)
Income (loss) from continuing operations
before income taxes		(52,184	)		(31,479	)		(2,389	)		35,047		(51,005	)
Provision for income taxes		-			-			-			-		-
Income (loss) from continuing operations		(52,184	)		(31,479	)		(2,389	)		35,047		(51,005	)
Income from discontinued operations		-			-			(1,179	)		-		(1,179	)
Net income (loss)		(52,184	)		(31,479	)		(3,568	)		35,047		(52,184	)
Preferred dividends and amortization
of convertible preferred stock
issuance costs		-			-			-			-		-
Net income (loss) applicable to
common stock	$	(52,184	)	$	(31,479	)	$	(3,568	)	$	35,047	$	(52,184	)

23

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)

Nine Months Ended September 30, 2007

							Freeport					Consolidated
	Parent			MOXY			Energy			Eliminations		McMoRan
	(In Thousands)
Revenues:
Oil and gas	$	-		$	227,381		$	-		$	-	$	227,381
Service		-			2,916			-			-		2,916
Total revenues		-			230,297			-			-		230,297
Costs and expenses:
Production and delivery costs		-			72,582			(39	)		-		72,543
Depreciation and amortization		-			127,579			-			-		127,579
Exploration expenses		-			52,163			-			-		52,163
General and administrative expenses		3,417			14,232			155			-		17,804
Gain on oil and gas derivative contracts		-			(10,695	)		-			-		(10,695	)
Start-up costs for Main Pass
Energy Hub™		-			-			7,802			-		7,802
Total costs and expenses		3,417			255,861			7,918			-		267,196
Operating loss		(3,417	)		(25,564	)		(7,918	)		-		(38,899	)
Interest expense		(23,287	)		(11,009	)		-			-		(34,296	)
Equity in losses of
consolidated subsidiaries		(46,695	)		-			-			46,695		-
Other income, net		1,378			(2,254	)		-			-		(876	)
Income (loss) from continuing operations
before income taxes		(72,021	)		(38,827	)		(7,918	)		46,695		(72,071	)
Provision for income taxes		-			-			-			-		-
Income (loss) from continuing operations		(72,021	)		(38,827	)		(7,918	)		46,695		(72,071	)
Income from discontinued operations		-			301			(251	)		-		50
Net income (loss)		(72,021	)		(38,526	)		(8,169	)		46,695		(72,021	)
Preferred dividends and amortization
of convertible preferred stock
issuance costs		(1,552	)		-			-			-		(1,552	)
Net income (loss) applicable to
common stock	$	(73,573	)	$	(35,526	)	$	(8,169	)	$	46,695	$	(73,573	)

24

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW (UNAUDITED)

Nine Months Ended September 30, 2008

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)
Cash flow from operating activities:
Net cash provided by (used in)
continuing operations	$	20,519		$	618,661		$	(4,914	)	$	634,266
Net cash provided by discontinued
operations		-			-			1,897			1,897
Net cash provided by (used in)
operating activities		20,519			618,661			(3,017	)		636,163
Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(186,904	)		-			(186,904	)
Acquisition of oil and gas properties, net		-			(613	)		-			(613	)
Net cash used in investing activities		-			(187,517	)		-			(187,517	)
Cash flow from financing activities:
Net payments under revolving credit
facility		-			(274,000	)		-			(274,000	)
Dividends and inducement payments on
convertible preferred stock		(20,883	)		-			-			(20,883	)
Payments for induced conversion of
convertible senior notes		(2,663	)		-			-			(2,663	)
Proceeds from exercise of stock
options, warrants and other		4,705			-			-			4,705
Investment from parent		(1,802	)		-			1,802			-
Net cash provided by (used in)
financing activities		(20,643	)		(274,000	)		1,802			(292,841	)
Net increase (decrease) in cash and
Cash equivalents		(124	)		157,144			(1,215	)		155,805
Cash and cash equivalents at beginning
of year		143			3,446			1,241			4,830
Cash and cash equivalents at end of
year	$	19		$	160,590		$	26		$	160,635

25

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW (UNAUDITED)

Nine Months Ended September 30, 2007

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)
Cash flow from operating activities:
Net cash provided by (used in)
continuing operations	$	(212	)	$	106,979		$	(4,373	)	$	102,394
Net cash provided by discontinued
operations		-			302			371			673
Net cash provided by (used in)
operating activities		(212	)		107,281			(4,002	)		103,067
Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(109,165	)		-			(109,165	)
Acquisition of oil and gas properties, net		-			(1,051,302	)		-			(1,051,302	)
Proceeds from restricted investments		3,037			-			-			3,037
Increase in restricted investments		(126	)		-			-			(126	)
Net cash used in investing activities		2,911			(1,160,467	)		-			(1,157,556	)
Cash flow from financing activities:
Net borrowings under revolving credit
facility		-			284,250			-			284,250
Proceeds from unsecured bridge loan
facility		800,000			-			-			800,000
Proceeds from senior secured term loan					100,000						100,000
Repayment of senior secured term loan					(100,000	)					(100,000	)
Financing costs		(18,268	)		(12,948	)		-			(31,216	)
Dividends paid on convertible preferred
stock		(1,121	)		-			-			(1,121	)
Proceeds from exercise of stock
options, warrants and other		1,065			-			-			1,065
Investment from parent		(800,586	)		781,786			18,800			-
Net cash provided by (used in)
financing activities		(18,910	)		1,053,088			18,800			1,052,978
Net increase in cash and cash
equivalents		(16,211	)		(98	)		14,798			(1,511	)
Cash and cash equivalents at beginning
of year		16,593			1,030			207			17,830
Cash and cash equivalents at end of
year	$	382		$	932		$	15,005		$	16,319

11. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan’s ratio of earnings to fixed charges was 3.2 to 1.0 for the nine months ended September 30, 2008. McMoRan sustained losses from continuing operations totaling $72.1 million for the nine months ended September 30, 2007, which were inadequate to cover its fixed charges of $40.2 million for that period.  For this calculation, earnings consist of income (loss) from continuing operations and fixed charges. Fixed charges include provision for income taxes, interest and that portion of rent deemed representative of interest.

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TABLE OF CONTENTS

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, 2008, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2008 and 2007, and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2008 and 2007. 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 interim 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, 2007, and the related consolidated statements of operations, cash flow and changes in stockholders’ equity (deficit) for the year then ended (not presented herein), and in our report dated March 14, 2008, 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, 2007, 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 4, 2008

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TABLE OF CONTENTS

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, 2007 (2007 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 Consolidated Financial Statements included elsewhere in this Form 10-Q.

We engage in the exploration, development and production of oil and natural gas offshore in the Gulf of Mexico and onshore in the Gulf Coast area. 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. Our focused strategy enables us to make efficient use of our geological, engineering and production strengths in the areas where we have more than 35 years of operating experience. We also believe that our increased scale of operations in the Gulf of Mexico provides synergies and a strong platform from which we pursue our business strategy. Our oil and gas operations are conducted through MOXY, our principal operating subsidiary. In addition to our oil and gas operations, we are pursuing a multifaceted energy services development of the Main Pass Energy Hub™ (MPEH™) project, including the potential development of a liquefied natural gas (LNG) regasification and storage facility through our other wholly owned subsidiary, Freeport-McMoRan Energy.

We expect to continue to pursue growth in reserves and production through the exploration, exploitation and development of our existing oil and gas prospects and new potential prospects. Exploration will continue to be the focus in our continued efforts to maximize value. With our 2007 oil and gas property acquisition (Note 2) and other recent discoveries, we also have additional opportunities to create value through exploration, development and exploitation of these properties.

Our technical and operational expertise is primarily in the Gulf of Mexico. We leverage this expertise by attempting to identify exploration opportunities with high potential. Our exploration strategy, which we refer to as the “deeper pool concept,” involves exploring prospects that lie below shallower intervals on the Deep Miocene geologic trend that have had significant past production. A significant advantage to our “deeper pool” exploration strategy is that the targets are generally large and infrastructure to support production is in most cases already available, meaning discoveries generally can be brought on line quickly and at relatively low development costs. We believe our techniques for identifying reservoirs using structural geology augmented by 3-D seismic data will enable us to identify and exploit additional “deeper pool” prospects at drilling depths exceeding 15,000 feet.

Implementing our business strategy will require significant expenditures during 2008 and beyond. During the nine months ended September 30, 2008, we invested $186.9 million on capital-related projects primarily associated with our exploration activities and the subsequent development of the related discoveries. Our exploration, development and other capital expenditures for 2008 are expected to approximate $270 million, including approximately $95 million for exploration drilling and $175 million in development costs. These expenditures may also increase as necessary for purposes of funding development costs associated with additional successful wells or to fund additional exploration opportunities that may be presented to us.  We also expect to spend approximately $60 million in 2008 to abandon and remove oil and gas structures from the Gulf of Mexico, most of which is associated with the removal of structures damaged during the 2005 and 2008 hurricane seasons.  We plan to fund our exploration, development and reclamation activities with our cash on hand, operating cash flow and availability under our variable rate senior secured revolving credit facility (credit facility).

We will require commercial arrangements for the MPEH™ project to obtain financing, which may be in the form of additional debt and/or equity transactions. However, external financing in the capital

28

markets is currently not available, and the ultimate outcome of our efforts to enter into commercial arrangements on reasonable terms to develop the MPEH™ project and obtain additional financing is subject to various uncertainties, many of which are beyond our control.  For additional information on these and other risks, see Item 1A. “Risk Factors” included in our 2007 Form 10-K.  For additional information with respect to our liquidity position, see “Capital Resources and Liquidity” below.

Additionally, notwithstanding the discussion of our business strategy, liquidity position and certain other forward-looking statements included in this Form 10-Q or the materials incorporated by reference herein, we are closely monitoring the recent disruption in the global financial and credit markets, as well as the recent significant decline in the market price of oil and natural gas, each of which have been widely publicized and may ultimately have a material affect on one or more facets of our business and overall business strategy. We understand the need to be prepared for difficult conditions in the near term, and as these events continue to unfold we will be in a better position to evaluate and respond to any impact on our operations, particularly if weak conditions persist or energy prices continue to decline.  In the interim, we intend to maintain focus on implementing our core business plans as discussed herein.

North American Natural Gas and Oil Market Environment

Market prices of natural gas and crude oil have significantly decreased from the highs of earlier in the year associated with inventories and demand concerns in connection with recent economic and financial market turmoil.  North American natural gas averaged $9.02 per MMbtu during the third quarter of 2008.  The spot price for natural gas was $7.22 per MMbtu on November 4, 2008.  Crude oil prices have also dropped significantly since reaching record levels of over $140 per barrel during the second quarter of 2008.  The average oil price for the third quarter of 2008 was $118.67 per barrel. The spot price for crude oil was $70.53 per barrel as of November 4, 2008. Future oil and natural gas prices are subject to change and these changes are not within our control (see Item 1A. “Risk Factors” included in our 2007 Form 10-K).

OPERATIONAL ACTIVITIES

Oil and Gas Activities

Our 2007 oil and gas property acquisition significantly expanded our scale of operations. For additional information regarding this acquisition see Note 2 as well as Notes 2 and 6 of our 2007 Form 10-K.  Since 2004, we have participated in 17 discoveries on 33 prospects that have been drilled and evaluated. In 2007, we made a significant “deep gas” discovery called Flatrock on OCS Block 310 at South Marsh Island Block 212.  We are developing plans to participate in the drilling of additional deep gas exploratory wells in 2008, including the Gladstone East prospect on Louisiana State Lease 340, which lies below the significant historical shallow production at Mound Point and the Ammazzo prospect, located on South Marsh Island Block 251.

29

Following the initial discovery at Flatrock on South Marsh Island Block 212 in the OCS 310/Louisiana State Lease 340 area in approximately 10 feet of water, we have drilled five successful wells and continue to pursue opportunities in the area aggressively.  The first three wells are currently producing.  Recent activities from the field include the commencement of production at the Flatrock No. 3 (location “D”) well in the Operc section on July 31, 2008, a successful production test at the No. 4 development well (location “C”) in the Rob-L section and logged pay in the Rob-L section at the No. 5 development well (location “E”). The No. 6 delineation well, located on South Marsh Island Block 217, commenced drilling on October 28, 2008 and is targeting the deeper Operc sand and will possibly penetrate the upper Gyro section on the Flatrock/Hurricane Deep structure.  Successful wells can be brought on line quickly using the Tiger Shoal facilities in the immediate area.  We have a 25.0 percent working interest and an 18.8 percent net revenue interest in the Flatrock wells.

The following is a status report on activities in the Flatrock area:

Flatrock Wells	Total Pay Intervals	Net Feet of Pay a	Status b
No. 1 – “A” location Discovery Well	8	260	Producing from the Operc section
No. 2 – “B” location Delineation Well	8	289	Producing from the primary Rob-L sand
No. 3 – “D” location Delineation Well	8	256	Producing from the Operc section
No. 4 – “C” location Development Well	2	116	Successful production test in the primary Rob-L sand indicated a gross rate of approximately 124 MMcfe/d, 23 MMcfe/d net to us; expected to commence production by year end 2008
No. 5 – “E” location c Development Well	2	100	Drilling ahead at 16,700’ to a potential total depth of 18,400’
No. 6 – “F” location d Delineation Well	n/a	n/a	Spud October 28, 2008; drilling below 3,100’ with proposed total depth of 19,700’

a.   Confirmed with wireline logs.

b.   Status is reported as of November 4, 2008.

c.   Located 1,800 feet west of the Flatrock No. 4 well and between the Flatrock No. 1 and No. 2 wells.

d.   Located on South Marsh Island Block 217 and 3,100 feet southeast of the Flatrock No. 3 well.

We have investments in six in-progress or unevaluated wells totaling $96.7 million at September 30, 2008, including $22.7 million for the Blueberry Hill well, $15.4 million for the Mound Point South well, $2.0 million for the Tom Sauk well (all located at Louisiana State Lease 340), $29.5 million for the JB Mountain Deep well at South Marsh Island Block 224, $23.5 million for the South Timbalier Block 168 No. 1 well and $3.6 million for the Northeast Belle Isle well in St. Mary Parish, Louisiana.

We re-entered the South Timbalier Block 168 No. 1 wellbore, formerly known as the Blackbeard West No. 1 ultra deep exploratory well, with the Rowan Gorilla IV rig on March 18, 2008 and commenced drilling a new hole on April 16, 2008.  The well was previously drilled to a total depth of 30,067 feet by its former operators.  The well was drilled to a total depth of 32,997 feet in October 2008 and we have announced plans to complete and test the well. Previous logs indicated four potential hydrocarbon bearing zones that would require further evaluation.  The well will be temporarily abandoned while the necessary long-lead time completion equipment is procured for the high pressure test.  We will continue to review additional drilling opportunities on the flanks of the structure and on other acreage we hold in the ultra-

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deep trend.  Seismic data on the prospect has indicated the potential for significantly thicker sands on the flanks of the structure as confirmed in recent major deepwater discoveries.  We have a 32.3 percent working interest (after casing point) and a 26.3 percent net revenue interest in the South Timbalier Block 168 No. 1 wellbore.  To date, $107.0 million in gross costs have been spent on deepening activities associated with this well.  Our investment in the well approximates $27.0 million as of November 4, 2008.

The Tom Sauk exploratory well commenced drilling on August 14, 2008 and is drilling below 12,800 feet towards a proposed total depth of 19,000 feet to evaluate potential Operc and Gyro sands in the middle-Miocene.  Tom Sauk, which is located in less than 10 feet of water, is a deep gas prospect that lies below the significant historical shallow production at Mound Point.  We hold an 18.3 percent working interest and a 14.5 percent net revenue interest in the well.

The Northeast Belle Isle exploratory well commenced drilling on August 24, 2008 and is drilling below 16,100 feet towards a proposed total depth of 18,500 feet to evaluate potential Rob-L sands in the middle-Miocene.  We hold a 35.7 percent working interest and a 24.9 percent net revenue interest in the well.

We expect drilling operations to commence in November 2008 at the Ammazzo exploration prospect located on South Marsh Island Block 251 in 25 feet of water.  The Ammazzo prospect has a proposed total depth of 24,500 feet.  The Ammazzo prospect is targeting one of the largest undrilled deep structures below 15,000 feet on the Shelf of the Gulf of Mexico.  It is positioned on the southern portion of the structural ridge extending from the Flatrock and JB Mountain discoveries (located approximately 16 and 11 miles north-northwest, respectively), where we have successfully proven the existence of Rob-L, Operc and Gryo sands in the Middle Miocene.  We will operate the well and hold a 25.9 percent working interest and a 21.1 percent net revenue interest.

Our investments in Blueberry Hill, JB Mountain Deep and Mound Point South have been capitalized for a period in excess of one year following the completion of their initial drilling operations.  The Blueberry Hill well encountered four potentially productive zones below 22,200 feet in February 2005 and has been assigned proved reserves by an independent petroleum engineering firm. Initial completion activities were undertaken in the first half of 2007; however, the well was unable to produce because of a blockage above the perforated interval.  A sidetrack well was planned for late 2008; however, as a result of the 2008 Gulf of Mexico hurricane activity, the timing of the sidetrack has been delayed.

The JB Mountain Deep well reached its total depth of 24,600 feet in April 2006.  Wireline logs indicated potential hydrocarbon bearing sands at two depths.   A protective liner was set and the well was temporarily abandoned.  We will incorporate information obtained from the Blueberry Hill and the Hurricane Deep wells at South Marsh Island Block 217, which commenced production in January 2008, in the future plans for the JB Mountain Deep well.

The Mound Point South well was drilled to a total measured depth of 21,065 feet in September 2007.  Based on wireline logs, the well encountered potential hydrocarbon bearing sands; however, the well was temporarily abandoned in September 2007.  Completion of the Mound Point South well was deferred pending results of a similar well, the Tom Sauk well, which commenced drilling in third quarter 2008.

As discussed above, we recently completed negotiations to participate in the Ammazzo exploration prospect located on South Marsh Island Block 251 which is within a common depositional basin together with the Blueberry Hill, JB Mountain Deep, Mound Point South and Tom Sauk wells.  The areas surrounding these wells, the Tiger Shoal/Mound Point areas, demonstrate similar geologic settings and target the same deep Miocene sands.  We have performed more extensive geologic and geophysical evaluations of this basin over the past several months and believe that the results of the Tom Sauk and Ammazzo wells will provide additional data to determine the best techniques for the continued development of the Blueberry Hill, JB Mountain Deep and Mound Point South wells.

In August 2008, the drilling results for the Mound Point East well at Louisiana State Lease 340 were evaluated and deemed to be non-productive.  As a result, the well was plugged and abandoned.   We charged $10.8 million of costs incurred for drilling the well through June 30, 2008 to exploration

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expense in our second quarter 2008 results.   Approximately $4.3 million of costs incurred subsequent to June 30, 2008 was charged to exploration expense in the third quarter of 2008.

The King of the Hill well commenced production in August 2006 from the same reservoir as other productive wells in adjacent lease blocks. During 2007 the well began producing significant amounts of water and multiple attempts to establish production were unsuccessful.  In September 2008, we charged $10.8 million to depreciation, depletion and amortization expense to write off our remaining investment in the well.

In the second quarter of 2008, we recorded a $7.4 million charge to depletion, depreciation and amortization expense to write off our remaining investment in Ship Shoal Block 139 and West Cameron Block 176 as a result of the wells producing significant amounts of water and remedial operations being unable to restore production.

2008 Hurricane Activity

Hurricanes Gustav and Ike impacted Gulf of Mexico operations prior to making landfall on the Louisiana and Texas coasts on September 1, 2008 and September 13, 2008, respectively.  There was no significant damage to our properties resulting from Hurricane Gustav.  Assessments following Hurricane Ike identified several platforms, comprising approximately three percent of production and two percent of reserves, with significant structural damage.  Substantially all of our remaining production facilities are capable of resuming production pending restoration of downstream pipelines and facilities operated by third parties.  Drilling rigs used in our exploration and development activities sustained no significant damage in the storms and operations have resumed.

We recorded impairment charges of $21.9 million in the third quarter of 2008 to eliminate the carrying value of Ewing Banks Block 947 and South Marsh Island Block 49F after we concluded that the reserves associated with these properties would not be recoverable due to significant structural damage caused by Hurricane Ike.  Additionally, we recorded reclamation charges of $124.4 million in the third quarter of 2008 to record the additional reclamation costs for damaged properties and the acceleration of the timing of when these costs are expected to be incurred.  We also recorded $6.3 million in production and delivery costs related to damage assessment and repairs during the third quarter of 2008.  We expect to realize a substantial recovery under its insurance program for hurricane related costs, which are expected to be incurred over several years.  Insurance recovery will be recorded as income in our future financial results as claims are settled with insurers.

Acreage Position

As of September 30, 2008, we owned or controlled interests in 397 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering 1.32 million gross acres (0.60 million acres net to our interests), including 0.32 million gross acres associated with the ultra-deep trend. Our acreage position includes 1.21 million gross acres (0.55 million acres net to our interest) located on the outer continental shelf of the Gulf of Mexico, of which approximately 0.10 million gross acres (less than 0.01 million net to our interests) are scheduled to expire over the remainder of 2008.  None of our expiring acreage is located in the Louisiana State Lease 340 or the OCS 310 lease areas.  We also hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to other oil and gas exploration companies that would partially revert to us upon the achievement of a specified production threshold or the achievement of specified net production proceeds.

Production Update

As discussed above, Hurricanes Gustav and Ike impacted our production during the third quarter of 2008.  We have re-established production at a current rate of approximately 140 MMcfe/d, approximately 50 percent of average production rates in July and August of 2008.  Based on reports from third party operators of downstream facilities and pipelines, we expect significant additional production to be restored in the fourth quarter of 2008.

The operator of the Tiger Shoal facility, which processes production from the OCS 310/Lousiana State Lease 340 area including Flatrock, indicated no material damage to the structures and production at Flatrock was re-established on September 22, 2008.  The three wells are currently

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producing at a gross rate of approximately 160 MMcfe/d, 30 MMcfe/d net to us.  Exploration and development activities in this important area are continuing as previously scheduled.

Third-quarter 2008 production averaged 225 MMcfe/d net to McMoRan, compared with 185 MMcfe/d in the third quarter of 2007.  Prior to the September hurricane events, our quarter to date production averaged approximately 296 MMcfe/d.  Third quarter production includes approximately five MMcfe/d of royalty relief volumes associated with third quarter production volumes.  Revenue recognition from deep gas royalty relief was suspended during the second quarter because of the strength of natural gas prices during the quarter and forward prices as of June 30, 2008.  At June 30, 2008, we based our accounting on an estimate that annual average 2008 natural gas prices would exceed $10.38 per mmbtu, the then current threshold established by the Minerals Management Service (MMS) above which royalty relief is not available for 2008.   During the third quarter, natural gas prices have declined significantly and averaged $9.73 per mmbtu as of September 30, 2008.  As a result, third quarter 2008 results include an increase to revenues of $9.4 million associated with the recording of royalty relief associated with first and second quarter production.  If actual natural gas prices for the year 2008 average more than $10.34 per mmbtu (the current threshold), our revenues for the 2008 would decrease by $16.2 million to reflect higher royalties applicable to certain of our properties pursuant to MMS royalty relief regulations for deep drilling.

Based on current information from third party operators of downstream facilities, we currently expect aggregate production to average approximately 180 MMcfe/day and reach approximately 280-290 MMcfe/d in the first half of 2009.  The timing of restoring production is largely dependent on downstream pipelines and facilities operated by third parties.

MAIN PASS ENERGY HUB™ PROJECT

In addition to our oil and gas operations, we are continuing to pursue a multifaceted energy services development of the MPEH™ project, including the potential development of a liquefied natural gas (LNG) regasification and storage facility through Freeport Energy. As of September 30, 2008, we have incurred approximately $49.7 million of cumulative cash costs associated with our pursuit of the establishment of MPEH™, including $1.5 million in the nine months ended September 30, 2008.  These expenditures include the funding of the advancement of license process and the pursuit of commercial and financing arrangements for the project.  As of September 30, 2008, we have recognized a liability of $11.0 million relating to the future reclamation of the MPEH™ related facilities. The actual amount and timing of the obligation for reclamation of these structures is dependent on the success of our efforts to use these facilities at the MPEH™ project as described above.

For additional information regarding the MPEH™ project, including estimates related to capital expenditures, see “Business — Business Strategy — Main Pass Energy Hub™ Project” in Items 1. and 2. “Business and Properties” in our 2007 Form 10-K.

We also maintain rights to a sulphur resource at Main Pass Block 299.  In August 2000, we ceased mining sulphur at this location because of low sulphur prices and high natural gasprices.  Following a prolonged period of sulphur prices in the $60-$80 per ton range, sulphur prices exceeded $600 per ton FOB Tampa, Florida during the third quarter of 2008, but have recently declined sharply.  We have engaged in discussions with sulphur consumers about the potential of producing this resource, which is estimated to contain approximately 60 million long tons of sulphur.  Developing the resource would require significant capital expenditures.  The recent economic conditions and sharp decline in phosphate fertilizer prices will likely prohibit development of this resource in the present circumstances.

RESULTS OF OPERATIONS

Our only segment is “Oil and Gas.” We are pursuing a new segment, “Energy Services,” whose start-up activities are reflected as a single expense line item within our consolidated statements of operations under the caption “Start-up Costs for Main Pass Energy Hub™.” See “Discontinued Operations” below for information regarding our former sulphur segment.

We use the successful efforts accounting method for our oil and gas operations, which requires exploration costs, other than costs of successful drilling and in-progress exploratory wells, to be charged to expense as incurred.  

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Our operating results have changed substantially following our 2007 oil and gas property acquisition (Note 2).  Our results of operations include amounts from these properties as summarized below (in thousands):

	Third Quarter					Nine Months
	2008			2007		2008			2007
Revenues:
Oil and natural gas	$	185,408		$	95,406	$	672,563		$	95,406
Service		2,841			1,875		8,475			1,875
Total revenues		188,249			97,281		681,038			97,281
Cost and Expenses:
Production and delivery costs		44,925	a		20,577		118,056	b		20,577
Depreciation and amortization		82,389			58,128		265,040			58,128
Exploration expenses		299			28		3,602			28
General and administrative expenses c		1,372			1,000		3,753			1,000
Total costs and expenses		128,985			79,733		390,451			79,733
Operating income	$	59,264		$	17,548	$	290,587		$	17,548

a.   Includes lease operating expenses of $29.7 million, $6.9 million for workover costs and $8.3 million for transportation, production taxes and other related costs for the third quarter of 2008.

b.   Includes lease operating expenses of $82.3 million, $14.0 million for workover costs and $21.8 million for transportation, production taxes and other related costs for the nine months ended September 30, 2008.

c.   Only includes cost directly allocated to the acquired properties and excludes all compensation costs. Amounts primarily reflect costs related to our office in Houston, Texas.

In addition to the revenues and expenses from the 2007 oil and gas property acquisition, our third quarter 2008 operating income of $18.1 million reflects (a) $152.6 million of Hurricane Ike related charges; (b) aggregate realized and unrealized gains of $80.4 million associated with the cash settlement and mark-to-market adjustment of the fair values of our oil and gas derivative contracts; (c) an impairment charge of $10.8 million related to High Island Block 131; and (d) exploration expenses of $15.1 million.

Our third-quarter 2007 operating loss of $25.7 million reflects (a) exploration expenses of $37.1 million, which includes $12.5 million in seismic data costs associated with the 2007 oil and gas property acquisition and $20.3 million of non-productive exploratory well costs primarily associated with the Cas well at South Timbalier Block 98; (b) an impairment charge of $13.6 million to write off the remaining net book value of the Cane Ridge field; and (c) a gain of $10.7 million associated with the mark-to-market adjustment of the fair values of our oil and gas derivative contracts.

Our operating income for the nine months ended September 30, 2008 totaled $144.1 million, which includes (a) $152.6 million of Hurricane Ike related charges; (b) aggregate realized and unrealized losses of $35.6 million associated with the cash settlement and mark-to-market adjustment of the fair values of our oil and gas derivative contracts; (c) stock compensation expense primarily associated with immediately vested stock options totaling $25.5 million (see “Stock-Based Compensation” below and Note 8); (d) $16.8 million of non-productive exploratory well drilling and related costs; (e) impairment charges of $18.9 million to write off the remaining book value of certain fields; and (f) $3.4 million of insurance recovery related to the final settlement for inspection and repairs associated with underwater platform damage at Main Pass Block 299 from Hurricane Katrina.

Our operating loss for the nine months ended September 30, 2007 totaled $36.9 million, which includes (a) $52.2 million of exploration expenses, including $21.7 million of non-productive drilling and related costs; (b) $7.8 million of start-up costs associated with MPEH™; (c) the Cane Ridge impairment charge discussed above; (d) $3.4 million of charges to depreciation, depletion and amortization expense to increase the estimates for the accrued reclamation costs for the Vermilion Block 160 and Ship Shoal Block 296 fields; and (e) the gain on the derivative contracts as discussed above.  For the nine months

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ended September 30, 2007, our non-cash compensation costs associated with stock-based awards totaled $10.9 million, which included $5.3 million of costs charged to exploration expense.

Summarized operating data are as follows:

	Third Quarter		Nine Months
	2008a	2007	2008 a		2007
Sales volumes:
Gas (thousand cubic feet, or Mcf)	13,537,100	12,645,100	49,637,500	b	19,401,900
Oil (barrels)a	811,900	671,300	3,027,800	b	1,323,900
Plant products (per Mcf equivalent) c	2,288,100	320,100	6,959,300	b	1,000,700
Average realizations:
Gas (per Mcf)	$ 10.67	$ 6.17	$ 10.62		$ 6.74
Oil (per barrel)a	124.05	75.08	114.07		66.80

a.   Sales volumes associated with the properties acquired in August 2007 include the following:

	Third Quarter				Nine Months
	2008		2007		2008		2007
Gas (Mcf)		8,559,900		9,694,000		35,487,000		9,694,000
Oil (barrels)		530,900		498,000		2,087,400		498,000
Plant products (per Mcf equivalent)		1,534,700		211,000		5,164,500		211,000

b.   Results include increases to natural gas volumes of 0.7 billion cubic feet (Bcf), oil and condensate volumes of 1,400 barrels and plant product volumes of 0.2 Bcf to record royalty relief amounts associated with first and second quarters.  Pursuant to Minerals Management Service (MMS) regulations, if the annual average NYMEX market price for natural gas does not exceed the MMS’s annual price threshold (currently $10.34 per MMbtu for 2008), then relief is available under the program and royalties would not be due to the MMS.  As previously disclosed, in the second quarter of 2008, we suspended royalty relief recognition due to the strength of natural gas prices during the quarter and the expectation that prices would remain strong.  During the third quarter of 2008, natural gas prices declined significantly.  Based on the year to date average NYMEX market price and the forward price curve for natural gas, we currently expect that we will be eligible to receive this relief in 2008.  Sales volumes and realizations adjusted to include royalty relief for the first and second quarters of 2008 follows:

	2008
	1st Quarter		2nd Quarter
Gas (Mcf)		17,875,400		18,225,000
Oil (barrels)		1,089,800		1,126,100
Plant products (per Mcf equivalent)		2,459,600		2,211,600
Average realizations:
Gas (per Mcf)		$ 9.06		$ 12.12
Oil (per barrel)		97.40		123.00

c.   Results include approximately $27.8 million and $73.6 million of revenues associated with plant products (ethane, propane, butane, etc.) during the third quarter and nine months ended September 30, 2008, respectively.  Plant product revenues for the comparable prior year periods totaled $2.4 million and $7.7 million.  One Mcf equivalent is determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

Oil and Gas Operations

As shown in the table above, the 2007 oil and gas property acquisition had a significant impact on our operating results for the third quarter and nine months ended September 30, 2008.

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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	$	131,018		$	227,381
Increase (decrease)
Price realizations:
Natural gas		18,574			45,318
Oil and condensate		14,575			46,807
Sales volumes:
Natural gas		15,246			33,088
Oil and condensate		5,151			4,886
Properties acquired in 2007		90,002			577,156
Plant products revenues		8,160			12,069
Other		(38	)		250
Oil and natural gas revenues – current year period	$	282,688		$	946,955

Our oil and natural gas sales volumes totaled 20.7 billion cubic feet of natural gas equivalent (Bcfe) in the third quarter of 2008 and 17.0 Bcfe in the third quarter of 2007. The increase in 2008 from 2007 reflects the 2007 oil and gas property acquisition as well as increased production from our other properties.  Average realizations received for both oil and natural gas sold during the third quarter of 2008 increased 73 percent for oil and 53 percent for natural gas over amounts received in 2007 (see “—North American Natural Gas and Oil Market Environment” above). Revenues from plant products totaled $27.8 million in the third quarter of 2008 compared with $2.4 million in the prior year period.

Our oil and natural gas sales volumes totaled 74.8 Bcfe and 28.3 Bcfe in the nine months ended September 30, 2008 and 2007, respectively.  The increase in 2008 from 2007 reflects the 2007 oil and gas property acquisition as well as increased production from our other properties.  Average realizations received for both oil and natural gas sold during the nine months ended September 30, 2008 increased 81 percent for oil and 43 percent for natural gas over amounts received in 2007 (see “—North American Natural Gas and Oil Market Environment” above). Revenues from plant products totaled $73.6 million for the nine months ended September 30, 2008 compared with $7.7 million in the prior year period.

Our service revenues totaled $2.6 million for the third quarter of 2008 and $9.3 million for the nine months ended September 30, 2008 compared to $2.2 million and $2.9 million for the comparable periods last year.  These increases were related to additional production and handling fees from the processing of third party production and reimbursements of standard industry overhead fees associated with the 2007 oil and gas property acquisition.

Production and delivery costs.The following table reflects our production and delivery costs for the third quarter and nine months ended September 30, 2008 and 2007 (in millions, except per Mcfe amounts):

	Third Quarter						Nine Months
		Per			Per			Per		Per
	2008	Mcfe	2007		Mcfe		2008	Mcfe	2007	Mcfe
Lease operating expense	$37.7	$1.82	$20.1		$1.18		$106.4	$1.42	$36.0	$1.27
Workover costs	17.0	0.82	9.4		0.55		38.0	0.51	15.9	0.56
Insurance	4.7	0.23	7.2		0.43		17.6	0.23	14.1	0.50
Transportation and production taxes	10.4	0.50	1.8		0.11		31.4	0.42	5.9	0.21
Other	0.1	0.01	(0.3	)	(0.02	)	1.7	0.02	0.6	0.02
Total production and delivery costs	$69.9	$3.38	$38.2		$2.25		$195.1	$2.60	$72.5	$2.56

The increase in lease operating expense from 2007 primarily reflects increased production associated with the 2007 oil and gas property acquisition.  Our workover costs during the nine months of 2008 primarily reflect remedial operations at Main Pass Block 299, Vermillion Block 398, the King of the Hill well at High Island Block 131 and South Timbalier Block 193.  During 2007, our workover costs were

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related primarily to work at Eugene Island Block 97, the Eugene Island Block 193 C-1 and C-2 wells and efforts to restore production from the Cane Ridge well at Louisiana State Lease 18055.

Our insurance costs have decreased as a result of reduced premium costs upon renewal of our property and well control coverage in 2008.  These incremental costs increased in the later part of 2007 for coverage of the oil and gas properties acquired in August 2007.  Increased production taxes over the prior year reflect the commencement of production from the Point Chevreuil and Laphroaig wells located in St. Mary, Parish, Louisiana as well as four additional wells drilled on the properties acquired in August 2007.

Hurricanes Gustav and Ike impacted the Gulf of Mexico operations prior to making landfall on the Louisiana and Texas coasts on September 1, 2008 and September 13, 2008, respectively.  There was no significant damage to our properties resulting from Hurricane Gustav.  We have recorded $6.3 million in production and delivery costs related to damage assessment and repairs during the third quarter of 2008 related to Hurricane Ike.

Depletion, depreciation and amortization expense.   The following table reflects the components of our depletion, depreciation and amortization expense for the third quarter and nine months ended September 30, 2008 and 2007 (in millions, except per Mcfe amounts):

	Third Quarter				Nine Months
		Per		Per		Per		Per
	2008	Mcfe	2007	Mcfe	2008	Mcfe	2007	Mcfe
Depletion and depreciation expense	$ 81.2	$3.92	$69.3	$4.08	$302.7	$4.05	$107.6	$3.80
Accretion expense	135.6	6.55	2.1	0.13	148.9	2.00	6.4	0.22
Impairment charges/losses	33.3	1.61	13.6	0.80	40.9	0.55	13.6	0.48
Total	$250.1	$12.08	$85.0	$5.01	$492.5	$6.60	$127.6	$4.50

Our depletion, depreciation and amortization rates are affected by estimates of proved reserve quantities, which are subject to a significant level of uncertainty, especially for fields with little or no production history.  Subsequent revisions to individual fields’ reserve estimates can yield significantly different depletion, depreciation and amortization rates.  The increase in our depletion, depreciation and amortization expense in the third quarter and nine months ended September 30, 2008 over prior years primarily reflects production from the 2007 oil and gas property acquisition and from new discoveries.

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.   The recent significant decline in the market prices for oil and natural gas could result in an impairment of the capitalized cost of individual properties which could adversely affect our results of operations in future periods.  See Item 1A., “Risk Factors” in our 2007 Form 10-K.

In the third quarter of 2008, we recorded impairment charges of $21.9 million and reclamation charges of $124.4 million associated with properties damaged by Hurricane Ike.  We also recorded an impairment charge of $10.8 million associated with the King of the Hill well in the third quarter of 2008.  In the second quarter of 2008, we recorded a $7.4 million charge to depletion, depreciation and amortization expense to write off our remaining investment in Ship Shoal Block 139 and West Cameron Block 176 (see “Oil and Gas Activities” above).

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

	Third Quarter						Nine Months
	2008			2007			2008			2007
Geological and geophysical
including 3-D seismic purchases a	$	8.6		$	15.9	b	$	26.5		$	25.7	b
Non-productive exploratory costs, including
related lease costs		4.4	c		20.3	d		16.8	c		21.7	d
Other		2.1			0.9			6.1			4.8
	$	15.1		$	37.1		$	49.4		$	52.2

a.   Includes compensation costs associated with outstanding stock-based awards totaling $2.1 million in the third quarter of 2008 and $12.2 million in the nine months ended September 30, 2008 compared with $1.0 million and $5.3 million of compensation costs during comparable periods in 2007 (see “Stock-Based Compensation” below and Note 8).

b.   Includes $12.5 million of seismic data purchases for the exploration acreage associated with the 2007 oil and gas property acquisition.

c.   Includes non-productive well costs of $4.3 million and $15.1 million related to the Mound Point East well in the third quarter and nine months ended September 30, 2008, respectively.  In August 2008, the Mound Point East well was determined to be non-productive and we charged $10.8 million to exploration expense in the June 30, 2008 financial statements.  In the third quarter of 2008, we charged an additional $4.3 million to exploration expense for the additional costs incurred.

d.   Primarily reflects the non-productive exploratory well costs associated with the “Cas” well at South Timbalier Block 98.

Other Financial Results

Operating  

General and administrative expense totaled $10.7 million in the third quarter of 2008 and $38.0 million for the nine months ended September 30, 2008 compared with $7.0 million in the third quarter of 2007 and $17.8 million for the nine months ended September 30, 2007.  We charged $2.4 million of related stock-based compensation costs to general and administrative expense during the third quarter of 2008 and $12.5 million for the nine months ended September 30, 2008 compared to $1.0 million and $5.2 million for the comparable periods in 2007 (see “Stock-Based Compensation” below).   Additionally, our general and administrative costs in the 2008 periods reflect increased personnel associated with administering the 2007 oil and gas property acquisition.

In the third quarter of 2008, we recorded an aggregate of $80.4 million in gains associated with our oil and gas derivative contracts, including $82.3 million of unrealized mark-to-market adjustments related to the fair values of open oil and gas derivative contracts at September 30, 2008 and $1.9 million of realized losses resulting from the expiration of put contracts during the quarter.   For the nine months ended September 30, 2008, we recorded an aggregate loss of $35.6 million in losses associated with our oil and gas derivative contracts, including $2.5 million of unrealized mark-to-market adjustments related to the fair values of open oil and gas derivative contracts at September 30, 2008 and $33.1 million of realized losses resulting from the settlement of contracts expiring during the year (Note 5).   We recorded an aggregate of $10.7 million in unrealized gains associated with our oil and gas derivative contracts in the third quarter and nine months ended September 30, 2007.

Non-Operating  

Interest expense totaled $10.9 million in the third quarter of 2008 and $40.5 million for the nine months ended September 30, 2008 compared with $22.9 million in the third quarter of 2007 and $34.3 million for the nine months ended September 30, 2007.  Capitalized interest totaled $1.0 million in the third quarter of 2008, $2.0 million in the third quarter of 2007, $3.8 million for the nine months ended September 30, 2008 and $4.5 million for the nine months ended September 30, 2007.  The decreased interest expense for 2008 reflects our lower average debt balances.

Other income (expense) totaled $0.2 million in the third quarter of 2008 and ($2.3) million for the nine months ended September 30, 2008 compared with other expense of $2.5 million in the third quarter of

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2008 and $0.9 million for nine months ended September 30, 2007.  Other income represents interest income earned during the third quarter of 2008.  Other expense primarily represents $1.0 million and $1.7 million of fees paid to induce the conversion of a portion of our 6% and 5¼% convertible senior notes during the nine months ended September 30, 2008, respectively, offset by interest income earned during the period.

Our income tax provision totaled $1.3 million in the third quarter of 2008 and $3.1 million for the nine months ended September 30, 2008.  Due to our net loss position in 2007, we did not record an income tax provision during 2007.  Federal tax regulations impose additional limitations on the utilization of net operating loss carry forwards from prior periods when a defined level of change in the stock ownership of certain shareholders is exceeded. Through September 30, 2008, no such change in ownership was determined. We continue to monitor stock ownership changes under the guidance of these provisions.  Should an ownership change be determined or considered probable of occurring during 2008, we will include the impact of such change in the period that determination is made.

Discontinued Operations

Our discontinued operations resulted in a net loss of $1.4 million in the third quarter of 2008 and $3.0 million for the nine months ended September 30, 2008 compared with losses of $1.2 million in the third quarter of 2007 and income of $0.1 million for the nine months ended September 30, 2007.  We recorded $4.2 million of finalized insurance recoveries associated with the Port Sulphur property damage claims resulting from the 2005 hurricanes in the nine months ended September 3, 2007.  The current aggregate estimated closure cost for Port Sulphur, Louisiana facilities is approximately $8.2 million.  We are accelerating the closure of these facilities and are considering several alternatives under our reclamation plans.  We incurred approximately $1.6 million of these costs in the nine months ended September 30, 2008.  We estimate that we may incur these costs over the next twelve months under our currently anticipated closure plan, which is subject to change pending regulatory approval of the final plans.

CAPITAL RESOURCES AND LIQUIDITY

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

	Nine Months Ended
	September 30,
	2008			2007
Continuing operations
Operating	$	634.3		$	102.4
Investing		(187.5	)		(1,157.6	)
Financing		(292.8	)		1,053.0

Discontinued operations
Operating	1.9		0.7
Investing	-		-
Financing	-		-
Total cash flow
Operating	636.2		103.1
Investing	(187.5	)	(1,157.6	)
Financing	(292.8	)	1,053.0

Nine-Month 2008 Cash Flows Compared with Nine-Month 2007

Operating Cash Flows                                                      

Increased operating cash flow from our continuing operations in 2008 reflect increased oil and natural gas production and revenues primarily associated with the 2007 oil and gas property acquisition (Note 2) and higher average realizations for both natural gas and oil.  

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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 $186.9 million for the nine months ended September 30, 2008 and are expected to approximate $270 million, including approximately $95 million for exploration drilling and $175 million in development costs in 2008. These expenditures may also increase as necessary for purposes of funding development costs associated with additional successful wells or to fund additional exploration opportunities that may be presented to us.  We also expect to spend approximately $60 million in 2008 to abandon and remove oil and gas structures from the Gulf of Mexico, most of which is associated with the removal of structures damaged during the 2005 and 2008 hurricane seasons.  We have cash of $160.6 million at September 30, 2008 which we expect to use in the fourth quarter of 2008 as we continue to restore production from the 2008 hurricanes and fund near term capital expenditures and abandonment costs.  We plan to fund our exploration and development activities with cash, operating cash flows and borrowings under our senior secured revolving credit facility (see “Senior Secured Revolving Credit Facilities” below).  We will require commercial arrangements to obtain financing for the MPEH™ project.  We may also need to raise additional capital through future equity and/or debt transactions to continue our drilling activities and other project developments.  However, given the recent developments in the global financial markets and the decline in oil and natural gas prices, it would be difficult to raise capital through equity or debt transactions in the near term.

Financing Cash Flows                                                      

Our financing activities during the nine months ended September 30, 2008 reflect net payments of amounts borrowed under our senior secured financing arrangements of $274.0 million. Financing cash flow in the same period of 2007 reflects the net borrowings of $1.1 billion (see “Senior Secured Revolving Credit Facility” and “Senior Term Loan” below).

Our continuing operations’ financing activities also included payments of dividends on our 6¾% mandatory convertible preferred stock (6¾% preferred stock) and inducement payments for the early conversion of our 6¾% preferred stock totaling $20.9 million in the nine months ended September 30, 2008 compared with dividends paid on our 5% mandatorily redeemable convertible preferred stock of $1.1 million in the same period of 2007. All outstanding shares of our 5% mandatorily redeemable convertible preferred stock were converted into common stock during the second quarter of 2007.  Proceeds received from the exercise of stock options totaled $4.7 million in the nine months ended September 30, 2008 and $1.1 million in the same period of 2007.  We also paid $2.7 million in inducement fees related to the conversion of our senior convertible notes during the nine months ended September 30, 2008.

Senior Secured Revolving Credit Facility

Our variable rate senior secured revolving credit facility (credit facility) is secured by substantially all of our oil and gas properties and matures in August 2012.  The borrowing capacity was $500 million at September 30, 2008 and pursuant to the terms of the credit facility, it was reduced to $450 million on October 1, and will be reduced on December 31, 2008 to $400 million.

Availability under the credit facility is subject to a borrowing base which is recalculated semi-annually each April 1 and October 1.  There were no borrowings outstanding at September 30, 2008.  We have $100 million of letters of credit issued under the credit facility to support the reclamation obligations assumed in the 2007 oil and gas property acquisition (Note 2).   At October 1, 2008, our unused borrowing capacity under the credit facility totaled $350 million.

The average interest rate on borrowings under the credit facility was 5.00 percent and 5.49 percent during the third quarter and nine months ended September 30, 2008, respectively.  The average interest rate on borrowings under the credit facility was 7.8 percent and 7.9 percent during the third quarter and nine months ended September 30, 2007, respectively.  Interest expense on the credit facility totaled $1.6 million and $10.6 million for the third quarter and nine months ended September 30, 2008, respectively, including $1.4 million and $5.1 million, respectively, of amortization expense associated with the related deferred financing costs and other fees.  During the third quarter and nine months ended September 30, 2007, interest expense totaled $5.0 million and $6.0 million, respectively, including $0.6 million and $1.4 million, respectively, of amortization expense and other fees.

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The credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities.  We were in compliance with these covenants at September 30, 2008.  During the third quarter of 2008, we entered into a second amendment to the credit facility which, among other things, (i) provided us with the ability to terminate, cancel or unwind any swap agreement associated with hedges of oil and gas prices that were previously entered into pursuant to the terms of the credit facility; and (ii) permits us to induce conversion of our 6¾% preferred stock into shares of our common stock subject to limitations on the amount of cash used to effect such inducments.  We induced the conversion of a portion of our 6¾% preferred stock in the third quarter of 2008 (Note 8).

Debt Conversion Transactions

During the nine months ended September 30, 2008, we privately negotiated transactions to induce the conversion of $39 million of our 6% convertible senior notes, scheduled to mature July 2, 2008 (6% notes), into approximately 2.75 million shares of our common stock.  We paid an aggregate of $1.0 million in cash to induce these conversions, which is reflected as non-operating expense in the consolidated statements of operations.  Additionally, $62 million of the 6% notes were converted into approximately 4.3 million shares of our common stock in accordance with the terms of the 6% notes during the nine months ended September 30, 2008 (including the 6% notes converted into shares of common stock upon maturity on July 2, 2008).

During the nine months ended September 30, 2008, we also privately negotiated transactions to induce the conversion of $40 million of our 5¼% convertible senior notes due October 6, 2011 (5¼% notes) into approximately 2.4 million shares of its common stock.  We paid an aggregate $1.7 million in cash to induce these conversions, which is reflected as non-operating expense in the consolidated statements of operations.  The 5¼% notes have a conversion price of $16.575 per share and are callable beginning on October 6, 2009 if the closing price of our common stock has exceeded 130% of the conversion price for at least 20 trading days in any consecutive 30-day period.

Senior Term Loan

Effective January 19, 2007, we entered into a senior term loan agreement (term loan).  The term loan agreement provided for a five-year, $100 million term loan facility. Proceeds at closing, net of related fees and discounts, totaled approximately $98.0 million.  We used the net proceeds to repay borrowings then outstanding at that time under our previous revolving credit facility.   At the closing of the 2007 oil and gas property acquisition, we repaid this loan.  See Note 6 of the 2007 Form 10-K for additional information regarding repayment of the term loan.

6¾% Mandatory Convertible Preferred Stock

In November 2007, we completed a public offering of 2.59 million shares of 6¾% preferred stock. In September 2008, we agreed in a privately negotiated transaction to induce conversion of approximately 990,000 shares of our 6¾% preferred stock, with a liquidation preference of approximately $99 million, into approximately 6.7 million shares of our common stock (based on the minimum conversion rate of 6.7204 shares of common stock for each share of 6¾% preferred stock). We paid an aggregate $7.4 million in cash to the holders of these shares to induce the conversion of this 6¾% preferred stock, which is recorded as a $7.4 million charge to preferred dividends in the third quarter of 2008.  Preferred dividend payment savings related to this transaction approximate $15 million through the November 2010 mandatory conversion date of the securities.  See Note 8 of our 2007 Form 10-K for information regarding our 6¾% preferred stock.

Commitments

In September 2008, we entered into a two-year drilling contract with Rowan Companies, Inc. for the new 240C class jack-up, Rowan-Mississippi.  This rig will enable us to continue to advance the execution of our deep and ultra deep exploration program on the Shelf of the Gulf of Mexico.  We expect drilling operations to commence with this rig at the Ammazzo exploration prospect located on South Marsh Island Block 251 in 25 feet of water in November 2008.  We plan to use this rig to drill an ultra-deep well similar to the well at South Timbalier Block 168, following its utilization in connection with the drilling of the Ammazzo prospect.  We expect the total contract value of approximately $160 million will be shared with our partners in our deep and ultra deep exploration program.

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STOCK-BASED COMPENSATION

For information regarding our accounting for stock-based awards see Note 1 of our 2007 Form 10-K.  Compensation cost charged against earnings for stock-based awards is shown below (in thousands).

	Third Quarter				Nine Months
	2008		2007		2008		2007
General and administrative expenses	$	2,359	$	1,084	$	12,480	$	5,228
Exploration expenses		2,151		1,003		12,198		5,279
Main Pass Energy Hub™ start-up costs		161		78		868		398
Total stock-based compensation cost	$	4,671	$	2,165	$	25,546	$	10,905

We had a minimal amount of stock options available for grant to our employees at December 31, 2007.  On January 28, 2008, our Board of Directors granted a total of 1,654,500 stock options subject to shareholder approval of the 2008 Stock Incentive Plan (2008 Plan).  The stock options were granted to our employees at an exercise price of $15.04 per share (the closing market price on that date), including immediately exercisable options for an aggregate of 445,000 shares.  Options representing 400,000 of these 445,000 shares were issued to our Co-Chairmen in lieu of cash compensation in 2008.  Stock options under the 2008 Plan and the 2004 Director Compensation Plan were also granted to non-employee directors and advisory directors effective June 1, 2008.  Approval of the 2008 Plan was received at the annual shareholders’ meeting held on June 5, 2008 when the closing market price was $34.40 per share. Accordingly, the related fair values of such grants was charged to expense beginning in the second quarter 2008 in accordance with SFAS 123R.  The weighted average option value of the 1,699,500 options granted during the nine months ended September 30, 2008 was $24.95.  See Note 10 of our 2007 Form 10-K.

As of September 30, 2008, total compensation cost related to nonvested, approved stock option awards not yet recognized in earnings was approximately $28.6 million, which is expected to be recognized over a weighted average period one year.

NEW ACCOUNTING STANDARDS

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), clarifies the definition of fair value within that framework, and expands disclosures about the use of fair value measurements. In many of its pronouncements, the FASB has previously concluded that fair value information is relevant to the users of financial statements and has required (or permitted) fair value as a measurement objective. However, prior to the issuance of this statement, there was limited guidance for applying the fair value measurement objective in GAAP. This statement does not require any new fair value measurements in GAAP.  We adopted SFAS No. 157 on January 1, 2008 with no material changes to our financial position or results of operations.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The fair value hierarchy consists of three broad levels:

·   Level 1:  valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority;

·   Level 2:  valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability;

·   Level 3:  valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.

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The only financial instruments reported at fair value are our derivative instruments, which are discussed in Note 5.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities.” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. We adopted SFAS No. 159 on January 1, 2008 with no impact on our financial statements.

In December 2007, the FASB issued SFAS No. 141(R), “Applying the Acquisition Method.”  SFAS 141(R) requires an acquirer to recognize 100 percent of the fair values of acquired assets, with limited exceptions, even if the acquirer has not acquired 100 percent of its target.  Additionally, contingent consideration arrangements and preacquisition contingencies will be measured at fair value on the acquisition date and included in the basis of the purchase price.  Transaction costs will now be expensed as incurred and not considered as part of the fair value of the acquisition; however, acquired research and development will no longer be expensed at acquisition, but instead will be capitalized as an indefinite-lived intangible asset.  SFAS 141(R) is effective for fiscal years beginning after December 15, 2008 and early adoption is not allowed. Our accounting for our 2007 oil and gas property acquisition is not affected by this new standard.

In December 2007, the FASB issued SFAS No. 160, “Accounting for Noncontrolling Interests.”  SFAS 160 clarifies the classification of noncontrolling interests in the consolidated balance sheet and the accounting for and reporting of transactions between the reporting entity and holders of these noncontrolling interests.  Under SFAS 160, noncontrolling interests (minority interests) are to be considered equity transactions and reflected accordingly in the balance sheet and related statement of cash flow.  SFAS 160 will require separate disclosure on the face of the income statement distinguishing between the controlling and noncontrolling interests. SFAS 160 is effective for fiscal years beginning after December 15, 2008 and early adoption is not permitted. We do not believe that SFAS No. 160 will have a material impact on our financial statements.

In March 2008, the FASB issued FAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133”.  SFAS No. 161 requires enhanced disclosure related to derivatives and hedging activities and thereby seeks to improve the transparency of financial reporting. Under FAS No. 161, entities are required to provide enhanced disclosures relating to: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedge items are accounted for under FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS No. 133”), and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 must be applied prospectively to all derivative instruments and non-derivative instruments that are designated and qualify as hedging instruments and related hedged items accounted for under SFAS No. 133 for all financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are currently evaluating the impact that SFAS No. 161 will have on our financial statements.

In May 2008, the FASB issued FASB Staff Position APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).”   This FASB Staff Position requires the issuer of certain convertible debt instruments that may be settled in cash (or other assets) on conversion to separately account for the liability (debt) and equity (conversion option) components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate.  This will require the accretion of the resulting discount on the liability component of the convertible debt, which will result in additional interest expense based on our nonconvertible debt borrowing rate.  This FASB Staff position is effective for fiscal years beginning after December 15, 2008 and must be applied retrospectively for all periods presented. We are currently evaluating the impact that this FASB Staff Position will have on our 5¼% notes and related interest expense.

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CAUTIONARY STATEMENT

Management’s Discussion and Analysis of Financial Condition and Results of Operations contain forward-looking statements.  All statements other than statements of historical fact included in this report, including, without limitation, statements regarding plans and objectives of our management for future operations and our exploration and development activities are forward-looking statements.

 This report includes “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements about our plans, strategies, expectations, assumptions and prospects.  “Forward-looking statements” are all statements other than statements of historical fact, such as: statements regarding our financial plans; our indebtedness; acquisitions; our exploration and development plans and the potential development of the MPEH™ project; the potential restart of our sulphur production operations at Main Pass Block 299; our ability to satisfy the MMS reclamation obligations with respect to Main Pass and our environmental obligations; drilling potential and results; anticipated flow rates of producing wells; anticipated initial flow rates of new wells; reserve estimates and depletion rates; general economic and business conditions; risks and hazards inherent in the production of oil and natural gas; demand and potential demand for oil and natural gas; trends in oil, natural gas prices and sulphur prices; amounts and timing of capital expenditures and reclamation costs; and our ability to obtain necessary permits for new operations.  Further information regarding these and other factors that may cause our future performance to differ from that projected in the forward looking statements are described in more detail under Item 1A. “Risk Factors” included in our 2007 Form 10-K.

–––––––––––––––––––––––––

Item 3.  Quantitative and Qualitative Disclosures about Market Risk.

Our senior secured revolving credit facility (see “Senior Secured Revolving Credit Facility” and Note 3) has a variable rate, which exposes us to interest rate risk.  At September 30, 2008, we have no outstanding borrowings under the revolving credit facility.  Because the interest rate on our 11.875% senior notes is fixed, the fair value of these notes fluctuates over time as result of changes in market interest rates, our market credit ratings and other factors.  Without consideration of other factors, the fair value of our 11.875% senior notes will generally increase as market interest rates fall and, conversely, will decrease as interest rates rise.  The estimated fair value of our 11.875 senior notes as of September 30, 2008 was approximately $288.0 million.  The fair value of our 5¼% convertible senior notes is more closely aligned with changes in our common stock price as opposed to changes in market interest rates. The related fair value was approximately $105.5 million as of September 30, 2008.

In connection with our 2007 oil and gas property acquisition (Note 2), we entered into various hedging contracts for a portion of our projected 2008-2010 sales of oil and natural gas (see “Gulf of Mexico Property Acquisition” and Note 5).  The sensitivity of a $1.00 per MMbtu change from the average swap price for the natural gas volumes and a $5.00 per barrel change in the average swap price for the oil volumes covered by the remaining outstanding hedging contracts is as follows (in millions):

		+/- $1.00/ MMbtu		+/- $5.00/ Bbl
2008	$	2.7	$	0.6
2009		7.3		1.6
2010		2.6		0.6

We are currently not sensitive to changes in prices on our natural gas and oil puts as we would only exercise the put option if the price of natural gas and oil reached levels below $6.00 and $50.00, respectively.  For more information, please refer to the consolidated financial statements and notes thereto included in our 2007 Form 10-K.

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Item 4.   Controls and Procedures.

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

(b) Changes in internal controls. There has been no change in our internal control over financial reporting that occurred during the second fiscal quarter 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.

Item 1A.  Risk Factors.

There have been no material changes to our risk factors since the year ended December 31, 2007. For more information, please read Item 1A. included in our Form 10-K for the year ended December 31, 2007.

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

(c) 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-month period ended September 30, 2008, and 0.3 million shares remain available for purchase.

Item 6.                      Exhibits.

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

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McMoRan Exploration Co.

SIGNATURE

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

	McMoRan Exploration Co.
	By:  /s/ Nancy D. Parmelee
	Nancy D. Parmelee
	Senior Vice President, Chief Financial Officer
	and Secretary
	(authorized signatory and Principal
	Financial Officer)
Date:  November 5, 2008

46

McMoRan Exploration Co.

Exhibit Index

		Filed
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-Q	Form	File No.	Date Filed
2.1	Agreement and Plan of Merger dated as of August 1, 1998		S-4	333-61171	10/06/1998
3.1	Amended and Restated Certificate of Incorporation of McMoRan		10-K	001-07791	03/25/1999
3.2	Certificate of Amendment to the Amended and Restated Certificate of Incorporation of McMoRan		10-Q	001-07791	05/13/2003
3.3	Amended and Restated By-Laws of McMoRan as amended effective January 30, 2006		8-K	001-07791	02/03/2006
4.1	Form of Certificate of McMoRan Common Stock		S-4	333-61171	10/06/1998
4.2	Rights Agreement dated as of November 13, 1998		10-K	001-07791	03/25/1999
4.3	Amendment to Rights Agreement dated December 28, 1998		10-K	001-07791	03/25/1999
4.4	Standstill Agreement dated August 5, 1999 between McMoRan and Alpine Capital, L.P., Robert W. Bruce III, Algenpar, Inc, J. Taylor Crandall, Susan C. Bruce, Keystone, Inc., Robert M. Bass, the Anne T. and Robert M. Bass Foundation, Anne T. Bass and The Robert Bruce Management Company, Inc. Defined Benefit Pension Trust		10-Q	001-07791	11/12/1999
4.5	Indenture dated as of July 2, 2003 by and between McMoRan and The Bank of New York, as trustee		10-Q	001-07791	08/14/2003
4.6	Collateral Pledge and Security Agreement dated as of July 2, 2003 by and among McMoRan, as pledgor, The Bank of New York, as trustee, and the Bank of New York, as collateral agent		10-Q	001-07791	08/14/2003
4.7	Purchase Agreement dated September 30, 2004, by and among McMoRan Exploration Co., Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and J.P. Morgan Securities Inc		8-K	001-07791	10/07/2004
4.8	Indenture dated October 6, 2004 by and among McMoRan and the Bank of New York, as trustee		8-K	001-07791	10/07/2004
4.9	Collateral Pledge and Security Agreement dated October 6, 2004 by and among McMoRan, as pledgor, The Bank of New York, as trustee and the Bank of New York, as collateral agent		8-K	001-07791	10/07/2004
4.10	Registration Rights Agreement dated October 6, 2004 by and among McMoRan, as issuer and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities Inc. and Jefferies & Company, Inc. as Initial Purchasers		8-K	001-07791	10/07/2004
10.1	Main Pass 299 Sulphur and Salt Lease, effective May 1, 1988		10-K	001-07791	04/16/2002

E-1

		Filed
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-Q	Form	File No.	Date Filed
10.2	IMC Global/FSC Agreement dated as of March 29, 2002 among IMC Global Inc., IMC Global Phosphate Company, Phosphate Resource Partners Limited Partnership, IMC Global Phosphates MP Inc., MOXY and McMoRan		10-Q	001-07791	08/14/2002
10.3	Amended and Restated Services Agreement dated as of January 1, 2002 between McMoRan and FM Services Company		10-Q	001-07791	08/14/2003
10.4	Letter Agreement dated August 22, 2000 between Devon Energy Corporation and Freeport Sulphur		10-Q	001-07791	10/25/2000
10.5	Asset Purchase Agreement dated effective December 1, 1999 between SOI Finance Inc., Shell Offshore Inc. and MOXY		10-K	001-07791	02/08/2000
10.6	Employee Benefits Agreement by and between Freeport-McMoRan Inc. and Freeport Sulphur		10-K	001-07791	04/16/2002
10.7	Purchase and Sales agreement dated January 25, 2002 but effective January 1, 2002 by and between MOXY and Halliburton Energy Services, Inc		8-K	001-07791	03/11/2002
10.8	Purchase and Sale Agreement dated as of March 29, 2002 by and among Freeport Sulphur, McMoRan, MOXY and Gulf Sulphur Services Ltd., LLP		10-Q	001-07791	05/10/2002
10.9	Purchase and Sale Agreement dated May 9, 2002 by and between MOXY and El Paso Production Company		10-Q	001-07791	08/14/2002
10.10	Amendment to Purchase and Sale Agreement dated May 22, 2002 by and between MOXY and El Paso Production Company		10-Q	001-07791	08/14/2002
10.11	Master Agreement dated October 22, 2002 by and among Freeport-McMoRan Sulphur LLC, K-Mc Venture LLC, K1 USA Energy Production Corporation and McMoRan		10-K	001-07791	03/27/2003
10.12	Purchase and Sale Agreement dated June 20, 2007 by and between Newfield Exploration Company as Seller and McMoRan Oil & Gas LLC as Buyer effective July 1, 2007		8-K	001-07791	06/22/2007
10.13	Amended and Restated Credit Agreement dated as of August 6, 2007, among McMoRan Exploration Co., as parent, McMoRan Oil & Gas LLC, as borrower, JPMorgan Chase Bank, N.A. Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc., as syndication agent, BNP Paribas, as documentation agent, and the lenders party thereto		10-Q	001-07791	11/01/2007
10.14	First Amendment to Credit Agreement dated as of June 20, 2008, among McMoRan Exploration Co., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto		10-Q	001-07791	08/07/2008

10.15 Second Amendment to Credit Agreement dated as of September 10, 2008, among McMoRan Exploration Co., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto X

E-2

		Filed
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-Q	Form	File No.	Date Filed
10.16*	McMoRan Adjusted Stock Award Plan, as amended and restated		10-Q	001-07791	05/10/2007
10.17*	McMoRan 1998 Stock Option Plan, as amended and restated		10-Q	001-07791	05/10/2007
10.18*	McMoRan 1998 Stock Option Plan for non-Employee Directors		10-Q	001-07791	05/10/2007
10. 19*	McMoRan Form of Notice of Grant of Nonqualified Stock Options under the 1998 Stock Option Plan		10-Q	001-07791	08/04/2005
10.20*	McMoRan 2000 Stock Incentive Plan, as amended and restated		10-Q	001-07791	05/10/2007
10.21*	McMoRan Form of Notice of Grant of Nonqualified Stock Options under the 2000 Stock Incentive Plan		10-Q	001-07791	08/04/2005
10.22*	McMoRan 2001 Stock Incentive Plan, as amended and restated		10-Q	001-07791	05/10/2007
10.23*	McMoRan 2003 Stock Incentive Plan, as amended and restated		10-Q	001-07791	05/10/2007
10.24*	McMoRan’s Performance Incentive Awards Program as amended effective February 1, 1999		10-K	001-07791	03/25/1999
10.25*	McMoRan Form of Notice of Grant of Nonqualified Stock Options under the 2001 Stock Incentive Plan		10-Q	001-07791	08/04/2005
10.26*	McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan		10-Q	001-07791	08/09/2007
10.27*	McMoRan Exploration Co. Executive Services Program		8-K	001-07791	05/05/2006
10.28*	McMoRan Form of Notice of Grants of Nonqualified Stock Options under the 2003 Stock Incentive Plan		10-Q	001-07791	08/04/2005
10.29*	McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan		10-Q	001-07791	08/09/2007
10.30*	McMoRan 2004 Director Compensation Plan, as amended and restated		10-Q	001-07791	05/10/2007
10.31*	Form of Amendment No. 1 to Notice of Grant of Nonqualified Stock Options under the 2004 Director Compensation Plan		8-K	001-07791	05/05/2006
10.32*	Agreement for Consulting Services between Freeport-McMoRan Inc. and B. M. Rankin, Jr. effective as of January 1, 1991)(assigned to FM Services Company as of January 1, 1996); as amended on December 15, 1997 and on December 7, 1998		10-K	001-07791	03/25/1999
10.33*	Supplemental Letter Agreement between FM Services Company and B.M. Rankin, Jr. effective as of January 1, 2008		10-K	001-07791	03/17/2008
10.34*	McMoRan Director Compensation		10-Q	001-07791	08/07/2008
10.35*	McMoRan Exploration Co. 2005 Stock Incentive Plan		10-Q	001-07791	05/10/2007

10.36*	Form of Notice of Grant of Nonqualified Stock Options under the 2005 Stock Incentive Plan	8-K	001-07791	05/06/2005
10.37*	Form of Restricted Stock Unit Agreement under the 2005 Stock Incentive Plan	10-Q	001-07791	08/09/2007

E-3

		Filed
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-Q	Form	File No.	Date Filed
10.38*	McMoRan Exploration Co. Supplemental Executive Capital Accumulation Plan		10-Q	001-07791	05/08/2008
10.39*	McMoRan Exploration Co. Supplemental Executive Capital Accumulation Plan Amendment One		10-Q	001-07791	05/08/2008
10.40*	McMoRan Exploration Co. 2008 Stock Incentive Plan.		8-K	001-07791	06/11/2008
10.41*	Form of Notice of Grant of Nonqualified Stock Options under the 2008 Stock Incentive Plan.		8-K	001-07791	06/11/2008
10.42*	Form of Restricted Stock Unit Agreement under the 2008 Stock Incentive Plan.		8-K	001-07791	06/11/2008
10.43*	Form of Notice of Grant of Nonqualified Stock Options and Restricted Stock Units under the 2008 Stock Incentive Plan (for grants made to non-management directors and advisory directors).		8-K	001-07791	06/11/2008
12.1	Computation of Ratio of Earnings to Fixed Charges		10-K	001-07791	03/17/2008
14.1	Ethics and Business Conduct Policy		10-K	001-07791	03/15/2004
15.1	Letter dated November 4, 2008 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

–––––––––––––––––––––––––

*  Indicates management contract or compensatory plan or agreement.

E-4