McMoran Exploration 10Q 2005 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, 2005
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. Yes X No __

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes X No __

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). Yes__ No X

On September 30, 2005, there were issued and outstanding 24,660,432 shares of the registrant’s Common Stock, par value $0.01 per share.

* In the aftermath of Hurricane Katrina, McMoRan Exploration Co. has temporarily moved its corporate headquarters to 5353 Essen Lane, Suite 350, Baton Rouge, Louisiana 70809, office phone (225-765-2200).


McMoRan Exploration Co.
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	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

Remarks	12

Report of Independent Registered Public Accounting Firm	13

Management's Discussion and Analysis of Financial Condition and Results of Operations	14

Quantitative and Qualitative Disclosures about Market Risk	25

Controls and Procedures	25

Part II. Other Information	25

Signature	26

Exhibit Index	E-1

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McMoRan Exploration Co.

Part I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

McMoRan EXPLORATION CO.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

	September 30,			December 31,
	2005			2004
	(In Thousands)
ASSETS
Cash and cash equivalents:
Continuing operations, includes restricted cash of $2.0 million
at September 30, 2005 and $3.7 million at December 31, 2004	$	174,299		$	203,035
Discontinued operations, all restricted		997			980
Restricted investments		15,120			15,150
Accounts receivable		21,685			27,403
Inventories		4,528			854
Prepaid expenses		2,265			1,122
Current assets from discontinued operations, excluding cash		2,550			2,563
Total current assets		221,444			251,107
Property, plant and equipment, net		162,330			97,262
Sulphur business assets		312			312
Restricted investments and cash		14,042			24,779
Other assets		8,832			10,460
Total assets	$	406,960		$	383,920

LIABILITIES AND STOCKHOLDERS’ DEFICIT
Accounts payable	$	49,618		$	33,997
Accrued liabilities		39,530			28,197
Accrued interest		5,523			5,635
Current portion of accrued oil and gas reclamation costs		-			238
Current portion of accrued sulphur reclamation cost		2,750			2,550
Current liabilities from discontinued operations		6,056			4,601
Total current liabilities		103,477			75,218
6% convertible senior notes		130,000			130,000
5¼% convertible senior notes		140,000			140,000
Accrued sulphur reclamation costs		12,606			12,086
Accrued oil and gas reclamation costs		22,402			14,191
Contractual postretirement obligation		14,802			15,695
Other long-term liabilities		15,564			16,711
Mandatorily redeemable convertible preferred stock		28,932			29,565
Stockholders' deficit		(60,823	)		(49,546	)
Total liabilities and stockholders' deficit	$	406,960		$	383,920

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Revenues:	(In Thousands, Except Per Share Amounts)
Oil and gas	$	41,411		$	3,704		$	83,666		$	10,218
Service		2,854			3,597			9,218			10,628
Total revenues		44,265			7,301			92,884			20,846
Costs and expenses:
Production and delivery costs		12,498			1,576			20,868			4,664
Depreciation and amortization		6,497			1,664			19,426			4,052
Exploration expenses		5,831			3,230			41,864			16,662
General and administrative expenses		5,496			3,804			15,132			10,193
Start-up costs for Main Pass Energy Hub™		2,692			2,666			7,577			8,660
Insurance recovery		-			-			(8,900	)		(1,074	)
Total costs and expenses		33,014			12,940			95,967			43,157
Operating income (loss)		11,251			(5,639	)		(3,083	)		(22,311	)
Interest expense		(4,006	)		(2,079	)		(11,887	)		(6,491	)
Equity in K-Mc Venture I LLC’s (loss) income		-			(125	)		-			318
Other income, net		1,527			287			4,547			664
Income (loss) from continuing operations		8,772			(7,556	)		(10,423	)		(27,820	)
Loss from discontinued operations		(1,624	)		(267	)		(3,591	)		(3,676	)
Net income (loss)		7,148			(7,823	)		(14,014	)		(31,496	)
Preferred dividends and amortization of convertible
preferred stock issuance costs		(402	)		(410	)		(1,217	)		(1,232	)
Net income (loss) applicable to common stock	$	6,746		$	(8,233	)	$	(15,231	)	$	(32,728	)

Basic net income (loss) per share of common stock:
Continuing operations		$0.34			$(0.46	)		$(0.47	)		$(1.70	)
Discontinued operations		(0.07	)		(0.02	)		(0.15	)		(0.21	)
Net income (loss) per share of common stock		$0.27			$(0.48	)		$(0.62	)		$(1.91	)

Diluted net income (loss) per share of common stock:
Continuing operations		$0.25			$(0.46	)		$(0.47	)		$(1.70	)
Discontinued operations		(0.04	)		(0.02	)		(0.15	)		(0.21	)
Net income (loss) per share of common stock		$0.21			$(0.48	)		$(0.62	)		$(1.91	)

Weighted average shares outstanding:
Basic		24,654			17,179			24,553			17,128
Diluted		43,178			17,179			24,553			17,128

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,
	2005			2004
	(In Thousands)
Cash flow from operating activities:
Net loss	$	(14,014	)	$	(31,496	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Loss from discontinued operations		3,591			3,676
Depreciation and amortization		19,426			4,052
Exploration drilling and related expenditures		31,634			9,439
Compensation expense associated with stock-based awards		1,347			1,025
Reclamation and mine shutdown expenditures		(4	)		(283	)
Amortization of deferred financing costs		1,669			1,056
Equity in K-Mc Venture I LLC’s income		-			(318	)
Other		(503	)		219
(Increase) decrease in working capital:
Accounts receivable		5,760			(3,984	)
Accounts payable, accrued liabilities and other		20,634			(538	)
Inventories and prepaid expenses		(4,816	)		611
Net cash provided by (used in) continuing operations		64,727			(16,541	)
Net cash used in discontinued operations		(2,532	)		(4,209	)
Net cash provided by (used in) operating activities		62,192			(20,750	)

Cash flow from investing activities:
Exploration, development and other capital expenditures		(102,857	)		(25,135	)
Proceeds from restricted investments		11,475			7,800
Increase in restricted investments		(437	)		(157	)
Net cash used in continuing operations		(91,819	)		(17,492	)
Net cash used in discontinued operations		-			(5,920	)
Net cash used in investing activities		(91,819	)		(23,412	)

Cash flow from financing activities:
Dividends paid on convertible preferred stock		(1,130	)		(1,148	)
Proceeds from exercise of stock options and other		2,038			367
Net cash provided by (used in) continuing operations		908			(781	)
Net cash activity - discontinued operations		-			-
Net cash provided by (used in) financing activities		908			(781	)
Net decrease in cash and cash equivalents		(28,719	)		(44,943	)
Cash and cash equivalents at beginning of year		204,015			101,899
Cash and cash equivalents at end of period		175,296			56,956
Less restricted cash from continuing operations		(2,031	)		-
Less restricted cash from discontinued operations		(997	)		(976	)
Unrestricted cash and cash equivalents at end of period	$	172,268		$	55,980

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 financial statements of McMoRan Exploration Co. (McMoRan), a Delaware Corporation, are prepared in accordance with U.S. generally accepted accounting principles. The consolidated financial statements of McMoRan include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and for which the right to participate in significant management decisions is not shared with other shareholders. McMoRan consolidates its wholly owned McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy) subsidiaries. On December 27, 2004, Freeport Energy acquired the remaining ownership interest in K-Mc Venture I LLC (K-Mc I) and began consolidating its results. For the periods between the date of K-Mc I’s inception (December 16, 2002) and December 27, 2004, McMoRan accounted for K-Mc I using the equity method. As a result of McMoRan’s exit from the sulphur business, its sulphur results have been presented as discontinued operations and the major classes of assets and liabilities related to the sulphur business have been separately shown for the periods presented.

All significant intercompany transactions have been eliminated. Certain reclassifications of prior year amounts have been made to conform to the current year presentation.

2. EARNINGS PER SHARE

Basic net income (loss) per share of common stock was calculated by dividing the net loss applicable to continuing operations, net loss from discontinued operations and net loss applicable to common stock by the weighted-average number of common shares outstanding during the periods presented. For purposes of the earnings per share computations, the net loss applicable to continuing operations includes preferred stock dividends and amortization of the related issuance costs.

McMoRan had a net loss from continuing operations for the third-quarter 2004 and nine-month periods ended September 30, 2005 and 2004. Accordingly, McMoRan’s diluted per share calculation for these periods was equivalent to its basic net loss per share calculation because it excluded 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 McMoRan’s 5% mandatorily redeemable convertible preferred stock, 6% convertible senior notes and 5¼% convertible senior notes. These instruments were excluded for these periods because they were considered to be anti-dilutive, meaning their inclusion would have decreased the reported net loss per share for these periods. The excluded common share amounts are summarized below (in thousands):

	Third Quarter					Nine Months
	2005			2004		2005		2004
In-the-money stock options ^{a ,b}		-	^c		745		1,454		841
Stock warrants ^a,d		-	^c		1,592		1,805		1,645
5% mandatorily redeemable convertible preferred stock ^e		-	^c		6,365		1,196		6,365
6% convertible senior notes ^f		-	^c		9,123		9,123		9,123
5¼% convertible senior notes ^g		8,446			N/A		8,446		N/A

a.	McMoRan uses the treasury stock method to determine the amount of in-the-money stock options and stock warrants to include in 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.

For the third-quarter 2005, McMoRan had net income from continuing operations which resulted in the assumed exercise or conversion of these securities in McMoRan’s diluted net income per share calculation (see table below for a reconciliation of McMcRan’s third-quarter 2005 diluted earnings per share calculation to its reported basic net income per share).

Includes stock warrants issued to K1 USA Energy Production Corporation in December 2002 (1.74 million shares) and September 2003 (0.76 million shares). The warrants are exercisable for McMoRan common stock at any time over their respective five-year terms at an exercise price of $5.25 per share. See Note 4 of McMoRan’s 2004 Form 10-K for additional information regarding the warrants.

e.	At the election of the holder, and before the shares mature on June 30, 2012, each outstanding share of 5% mandatorily redeemable convertible preferred stock (1.2 million shares outstanding as of September 30, 2005) is convertible into 5.1975 shares of McMoRan common stock. For

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additional information regarding McMoRan’s 5% convertible preferred stock see Note 5 of McMoRan’s 2004 Form 10-K.

The notes, issued in July 2003, are 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. Additional information regarding McMoRan’s 6% convertible senior notes is disclosed in Note 5 of its 2004 Form 10-K. Net interest expense on the 6% convertible senior notes totaled $2.1 million during the third quarters of 2005 and 2004 and $6.3 million for the nine-month periods ended September 30, 2005 and 2004.

The 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. Additional information regarding McMoRan’s 5¼% convertible senior notes is disclosed in Note 5 of its 2004 Form 10-K. Net interest on the 5¼% convertible senior notes totaled $2.0 million and $6.1 million for the third quarter and nine months ended September 30, 2005, respectively.

Outstanding stock options excluded from the computation of diluted net loss per share of common stock because their exercise prices were greater than the average market price of the common stock during the periods presented are as follows:

	Third Quarter				Nine Months
	2005		2004		2005		2004
Outstanding options (in thousands)		445		2,515		420		2,513
Average exercise price	$	21.54	$	17.99	$	21.71	$	17.99

The table below reconciles McMoRan’s basic net income per share to its diluted net income per share for the third quarter of 2005 (amounts in thousands, except per share data):

Basic net income from continuing operations	$	8,370
Add: Preferred dividends from assumed conversion of 5% mandatorily redeemable convertible preferred stock		402
Add: Net interest from assumed conversion of 6% convertible senior notes		2,128
Diluted income (loss) from continuing operations		10,900
Loss from discontinued sulphur operations		(1,624	)
Diluted net income (loss) applicable to common stock	$	9,276

Weighted average common shares outstanding for purpose of calculating basic net income per share		24,659
Assumed exercise of dilutive stock options		1,382
Assumed exercise of stock warrants		1,800
Assumed conversion of 5% mandatorily redeemable convertible preferred stock		6,214
Assumed conversion of 6% convertible senior notes		9,123
Weighted average common shares outstanding for purposes of calculating diluted net income per share		43,178

Diluted net income from continuing operations		$0.25
Diluted net loss from discontinued sulphur operations		(0.04	)
Diluted net income per share		$ 0.21

Stock-Based Compensation Plans. McMoRan accounts for its approved stock incentive or stock option plans, which are more fully described in Note 8 of McMoRan’s 2004 Form 10-K, under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, which require compensation cost for stock-based employee compensation plans to be recognized based on the difference on the date of grant, if any, between the quoted market price of the stock and the amount an employee must pay to acquire the stock. The following table illustrates the effect on net loss and earnings per share if McMoRan had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” which requires compensation cost for all stock-based compensation plans to be recognized based on the use of a fair value method (in thousands, except per share amounts):

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Net income (loss) applicable to common stock, as
reported	$	6,746		$	(8,233	)	$	(15,231	)	$	(32,728	)
Add: Stock-based compensation expense
included in reported net income (loss) for restricted stock units and employee stock options		261			54			1,121			618
Deduct: Total stock-based compensation
expense determined under fair value-
based method for all awards		(1,461	)		(1,050	)		(9,994	)		(7,101	)
Pro forma net income (loss) applicable to
common stock	$	5,546		$	(9,229	)	$	(24,104	)	$	(39,211	)

Net income (loss) per share:
Basic - as reported	$	0.27		$	(0.48	)	$	(0.62	)	$	(1.91	)
Basic - pro forma	$	0.22		$	(0.54	)	$	(0.98	)	$	(2.29	)

Diluted - as reported	$	0.21		$	(0.48	)	$	(0.62	)	$	(1.91	)
Diluted - pro forma	$	0.17	^a	$	(0.54	)	$	(0.98	)	$	(2.29	)

a. Amount based on 34,055,000 diluted shares outstanding (see diluted share reconciliation table above).

See Note 4 for information on a new accounting standard for share-based payments.

For the pro forma computations, the values of option grants were calculated on the date of the grants using the Black-Scholes option-pricing model. The pro forma effects on net loss are not representative of future years because of the potential changes in the factors used in calculating the Black-Scholes valuation and the number and timing of option grants and the requirement to adopt a new accounting standard by January 1, 2006 that will require all stock options to be charged to expense (Note 4). No other discounts or restrictions related to vesting or the likelihood of vesting of stock options were applied. The table below summarizes the weighted average assumptions used to value the options under SFAS 123.

	Third Quarter						Nine Months
	2005			2004			2005			2004
Fair value of stock options	$	N/A	^a	$	8.56		$	11.45		$	11.03
Risk free interest rate		N/A			3.8	%		4.3	%		3.9	%
Expected volatility rate		N/A			65.8	%		61.2	%		64.8	%
Expected life of options (in years)		N/A			7			7			7
Assumed annual dividend		-			-			-			-

a. There were no stock options granted during the third quarter of 2005.

3. OTHER MATTERS

Multi-Year Exploration Venture

During 2004, McMoRan and a private partner established a multi-year exploration venture with an initial combined commitment to spend $500 million to acquire and exploit high-potential, high-risk prospects, primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and in the Gulf Coast area. McMoRan and its exploration partner will share equally in all future revenues and costs, including related overhead costs, associated with the exploration venture’s activities, except for the Dawson Deep prospect at Garden Banks Block 625, where the exploration partner is participating in 40 percent of McMoRan’s interests. McMoRan estimates its management fee associated with the reimbursement of the exploration venture’s overhead costs will approximate $7 million in 2005. McMoRan recorded $1.8 million and $5.3 million of this management fee as service revenue during the third quarter and nine months ended September 30, 2005, respectively. Service revenues associated with the exploration venture totaled $3.0 million and $9.0 million for the third quarter and nine months ended September 30, 2004, respectively.

Since inception of the exploration venture, McMoRan and its private partner have participated in seven discoveries on the 15 prospects that have been drilled and evaluated. Production has commenced on three discoveries and development plans are being pursued for the other discoveries.

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Positive results from the potential discovery at Blueberry Hill at Louisiana State Lease 340 would bring McMoRan’s success rate to eight out of 16 prospects. McMoRan’s investment in the Blueberry Hill prospect totaled $10.6 million at September 30, 2005. The exploration venture currently has four unevaluated exploratory wells in progress. McMoRan’s investment for its unevaluated in-progress wells at September 30, 2005 totaled $13.7 million. During the third quarter and nine months ended September 30, 2005, McMoRan charged $2.7 million and $31.6 million, respectively, to exploration expense for nonproductive well drilling and related costs.

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, which may be substantial, in estimated reserves and related estimates of future cash flows. 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 McMoRan’s reserve estimation process see “Risk Factors” within Items 1. and 2. “Business and Properties” in McMoRan’s 2004 Form 10-K.

The Minuteman well at Eugene Island Block 213 commenced production on February 25, 2005. The well’s production decreased significantly from initial rates until stabilizing at a gross rate approximating 3 million cubic feet of natural gas equivalent per day (MMcfe/d). The well is currently shut-in because of mechanical problems and McMoRan and the operator are evaluating remedial opportunities for the well. McMoRan has been unable to develop meaningful estimates of ultimate recoverable reserves for the Minuteman well because of its geological complexity and the lack of sufficient production data. McMoRan will continue to monitor activity with respect to this well and accumulate data, including the effects of any potential remedial work that may be performed, to develop reserve estimates for this well, expected by year-end 2005. McMoRan’s net investment in the Minuteman well totaled $12.8 million at September 30, 2005. If the estimated undiscounted future net cash flows relating to this well’s estimated reserves are less than the related capitalized costs, McMoRan would reduce its investment accordingly.

Main Pass

McMoRan acquired the remaining ownership interest in K-Mc I that it did not previously own in December 2004 (Note 1). K-Mc I owns the oil facilities and related proved oil reserves at Main Pass Block 299 (Main Pass). The storm center of Hurricane Ivan passed within 20 miles east of Main Pass in September 2004. The Main Pass structures did not incur significant damage from Ivan but oil production was shut-in because of extensive damage to a third-party offshore terminal and connecting pipelines that provided throughput service for the sale of Main Pass sour crude oil. Insurance proceeds under McMoRan’s business interruption and property insurance policies have partially mitigated the financial impact of the storm (see below). In May 2005 production resumed at Main Pass following successful modification of existing storage facilities to accommodate transportation of oil production from the field by barge. At September 30, 2005, McMoRan’s property, plant and equipment included $7.5 million of costs associated with its efforts to modify these storage facilities. McMoRan is currently seeking reimbursement of these and subsequent modification costs under its insurance policy. As of September 30, 2005, McMoRan had received a total of $11.9 million of insurance proceeds related to its Main Pass business interruption claims, including $3.1 million recorded as a reduction to its acquisition cost of K-Mc I.

On August 29, 2005, the eye wall of Hurricane Katrina passed within 50 miles west of Main Pass. While Main Pass facilities and platforms did not suffer significant damage from Katrina, oil operations were temporarily shut-in to perform required repairs resulting from the storm. A subsurface inspection of all Main Pass structures, including those comprising the Main Pass Energy Hub^TMproject (MPEH^TM), is expected to be compled in the fourth quarter of 2005. Main Pass is expected to resume oil production in the fourth quarter of 2005. McMoRan will pursue partial reimbursement of the $2.5 million estimated costs for these repairs under its property insurance policy. No business interruption claims related to Hurricanes Katrina or Rita are currently anticipated.

The crude oil produced at Main Pass contains significant amounts of sulphur and is classified as sour crude, requiring the sulphur to be removed during the refining process. There is a limited market for sour crude oil and sour crude sells at a discount to other crude oils. McMoRan's current contract to sell its sour crude oil terminated on November 1, 2005. McMoRan is in discussions with a number of refineries

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regarding the sale of its sour crude oil from Main Pass. McMoRan anticipates that it will have a new marketing contract in place prior to year-end 2005.

The Main Pass oil lease was subject to a 25 percent overriding royalty retained by the original third-party owner of the Main Pass oil lease after 36 million barrels of oil were produced, but capped at a 50 percent net profits interest. In February 2005, the original owner agreed to eliminate this royalty interest and McMoRan agreed to assume the owner’s reclamation obligation associated with one platform and its related facilities located at Main Pass. McMoRan recorded $3.9 million to property, plant and equipment as well as accrued oil reclamation obligations related to the assumption of this liability pursuant to the requirements of Statement of Financial Accounting Standards No. 143 “Accounting of Asset Retirement Obligations” (SFAS 143). The amount of the ultimate estimated liability is $8.1 million on an undiscounted basis after adjusting for future inflation and applying a 10 percent market risk premium. As a result of this transaction, the original owner will be entitled to a 6.25 percent overriding royalty in new wells, if any, drilled on the Main Pass oil lease.

Hurricanes

In late August 2005, Hurricane Katrina significantly affected oil and gas industry facilities in the eastern and central Gulf of Mexico, as well as southeastern Louisiana and the Mississippi Gulf Coast. Although McMoRan’s oil and gas facilities and MPEH^TMplatforms did not suffer major damage from the storm, its oil facilities at Main Pass and Main Pass Block 86 (Shiner) were shut-in for repairs that are expected to be completed in the fourth quarter of 2005. In the aftermath of Katrina, McMoRan’s operating personnel temporarily relocated to Houston, Texas while its financial and administrative personnel established a temporary office in Baton Rouge, Louisiana. McMoRan's third-quarter 2005 results include related costs totaling $0.7 million associated with contributions, employee assistance and other administrative costs, with $0.5 of this amount being charged to general and administrative expense and the remaining $0.2 million being reflected as a component of exploration expense.

In late September 2005, Hurricane Rita significantly affected oil and gas industry facilities in the western and central Gulf of Mexico. Hurricane Rita did not result in any significant damage to McMoRan’s oil and gas production facilities but causedits producing properties to be shut-in pending availability of third-party downstream facilities that were significantly affected by the storm. Prior to Hurricane Katrina on August 29, 2005, McMoRan’s third-quarter production averaged approximately 55 MMcfe/d, including 2,900 barrels per day from Main Pass. McMoRan is currently producing at a rate of approximately 20 MMcfe/d, which continues to increase as McMoRan reestablishes production from its remaining shut-in properties, with most either commencing or anticipated to commence operations in November 2005. McMoRan expects full production rates from its properties producing prior to Hurricane Rita will be restored by the end of the fourth quarter of 2005.

Reversionary Interests

In February 2002, McMoRan sold three oil and gas properties for $60.0 million and retained a reversionary interest equal to 75 percent of the transferred interests following payout of $60 million plus a specified annual rate of return. The three properties sold were Vermilion Block 196 (Lombardi), Main Pass Block 86 and 80 percent of our interest in Ship Shoal Block 296 (Raptor). During the first quarter of 2005, McMoRan reached agreement with the third-party purchaser to assign to McMoRan the 75 percent reversionary interest in Raptor effective February 1, 2005 increasing McMoRan’s working interest to approximately 49.4 percent and its net revenue interest to 34.8 percent. Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout. Accordingly, McMoRan has an approximate 35.6 percent working interest and a 25.7 percent net revenue interest in the Lombardi field and a 53.4 percent working interest and a 38.5 percent net revenue interest in the Shiner field, where McMoRan was designated operator effective July 1, 2005.

In connection with the reversion of these properties, McMoRan recorded $2.1 million to property, plant and equipment as well as accrued oil reclamation obligations related to the assumption of McMoRan’s interest in these properties’ reclamation liabilities pursuant to SFAS 143. The ultimate estimated liabilities for these properties totaled $2.8 million on an undiscounted basis, after adjusting for future inflation and applying a 10 percent market risk premium.

Stock-Based Awards

On January 31, 2005, McMoRan’s Board of Directors granted 452,500 stock options, including immediately exercisable options for 255,000 shares to its Co-Chairmen. Options for 813,500 additional shares, including immediately exercisable options for 245,000 shares to McMoRan’s Co-Chairmen, were also granted on this date but their issuance was contingent on shareholder approval of a new

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stock incentive plan, which occurred on May 5, 2005. The immediately exercisable options were granted to McMoRan’s Co-Chairmen in lieu of cash compensation for 2005. All other stock options granted on January 31, 2005 become exercisable over a four-year period. Pursuant to current accounting requirements, the $1.51 per share difference between January 31, 2005 ($16.65 per share) and the market price on May 5, 2005 ($18.16 per share) is being charged to earnings as the options vest. In May 2005. McMoRan recorded noncash compensation charges of $0.4 million related to the immediately exercisable options granted to the Co-Chairmen.

McMoRan’s total recorded compensation cost associated with all stock-based awards was $0.3 million during the third quarter of 2005, $0.5 million during the third quarter of 2004, $1.3 million during the nine months ended September 30, 2005 and $1.0 million for the nine month ended September 30, 2004. McMoRan charged a portion of this stock-based compensation to exploration expense with the remainder being charged to general and administrative expense. The amount charged to exploration expense totaled $0.2 million during the third quarter of 2005, $0.2 million during the third quarter of 2004, $0.8 million for the nine months ended September 30, 2005 and $0.5 million for the nine months ended September 30, 2004.

Litigation

McMoRan is involved in litigation alleging that the directors of Freeport-McMoRan Sulphur Inc. breached their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the 1998 merger of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. The plaintiffs claim that the directors failed to take actions that were necessary to obtain the true value of Freeport-McMoRan Sulphur Inc. The plaintiffs also claim that McMoRan Oil & Gas Co. knowingly aided and abetted the breaches of fiduciary duty allegedly committed by the other defendants. In September 2002, the Chancery Court granted the defendants’ motion to dismiss. The plaintiffs appealed the court’s decision and in June 2003, the Delaware Supreme Court reversed the trial court’s dismissal and remanded the case to the trial court for further proceedings. The lawsuit was certified as a class action in January 2005. In February 2005 the defendants filed a motion for summary judgment, and on June 30, 2005, the Chancery Court rendered a written opinion denying defendants’ motion for summary judgment. A trial on the merits was scheduled for September 2005 but following Hurricane Katrina in late August 2005, the trial has been rescheduled for May 2006.

McMoRan believes that the merger transaction was properly considered by the boards of directors of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. and that the transaction was substantively and procedurally fair to the shareholders of both companies. Although the plaintiffs seek damages in a material amount, McMoRan cannot predict the outcome of this dispute or estimate the amount of any loss that may result to the company. Accordingly, no amounts have been accrued in McMoRan’s financial statements for this contingency.

Interest Cost

Interest expense excludes capitalized interest of $0.3 million in the third quarter of 2005 and $1.2 million for the nine months ended September 30, 2005. Capitalized interest totaled $0.2 million and $0.4 million for the third-quarter and nine-month periods ended September 30, 2004, respectively.

Pension Plan

During 2000, McMoRan elected to terminate its defined benefit plan. The plan’s termination is still pending approval from the Internal Revenue Service and the Pension Benefit Guaranty Corporation. See Note 8 of McMoRan’s 2004 Form 10-K for additional information regarding its defined benefit plan and its status. The components of net periodic pension benefit cost for the third quarter and nine months ended September 30, 2005 and 2004 for this plan are shown below (in thousands).

		Third Quarter						Nine Months
		2005			2004			2005			2004
Interest cost	$	60		$	100		$	143		$	288
Service cost		-			-			-			-
Return on plan assets		(30	)		(164	)		(115	)		(222	)
Net periodic cost (benefit)	$	30		$	(64	)	$	28		$	63

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4. NEW ACCOUNTING STANDARD

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS 123R). SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. SFAS 123R’s effective date is interim periods beginning after June 15, 2005. However, in April 2005 the Securities and Exchange Commission provided for a deferral of the effective date to fiscal years beginning after June 15, 2005. McMoRan will adopt SFAS 123R on January 1, 2006. Assuming prospective adoption of SFAS 123R on January 1, 2006 and based on currently outstanding employee stock options, McMoRan tentatively estimates the pro forma compensation charge for the full year of 2005 would approximate $10.1 million, would result in a pro forma net loss of $[3.3] million, $(0.13) per basic and diluted share for the third quarrter of 2005.

5. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan sustained losses from continuing operations of $10.4 million and $27.8 million for the nine months ended September 30, 2005 and 2004, respectively. These losses resulted in McMoRan’s earnings available for fixed charges to be $1.5 million for the nine-month 2005 period and a shortfall of $20.7 million for the nine-month 2004 period. McMoRan’s earnings available for fixed charges was inadequate to cover its fixed charges of $13.1 million for the nine-month 2005 period and its shortfall was inadequate to cover its fixed charges of $2.8 million for the nine-month 2004 period. For these calculations, earnings consist of income from continuing operations before income taxes and fixed charges. Fixed charges include interest and that portion of rent deemed representative of interest.

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Remarks

The information furnished herein should be read in conjunction with McMoRan’s financial statements contained in its 2004 Annual Report on 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. All such adjustments are, in the opinion of management, of a normal recurring nature.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the condensed consolidated balance sheet of McMoRan Exploration Co. (a Delaware corporation) as of September 30, 2005 and the related consolidated statements of operations for the three and nine-month periods ended September 30, 2005 and 2004 and the consolidated statements of cash flow for the nine-month periods ended September 30, 2005 and 2004. 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 to financial data 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, 2004, and the related consolidated statements of operations, changes in stockholders’ deficit, and cash flow for the year then ended (not presented herein), and in our report dated March 11, 2005, 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, 2004, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ ERNST & YOUNG LLP

New Orleans, Louisiana

November 2, 2005

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

OVERVIEW

In management’s discussion and analysis “we,”“us,” and “our” refer to McMoRan Exploration Co. and its wholly owned consolidated subsidiaries, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy). You should read the following discussions in conjunction with our consolidated financial statements, the related discussion and analysis of financial condition and results of operations and our discussion of “Business and Properties” in our Form 10-K for the year ended December 31, 2004 (2004 Form 10-K), filed with the Securities and Exchange Commission. The results of operations reported and summarized below are not necessarily indicative of future operating results. Unless otherwise specified, all references to Notes refers to Notes to Consolidated Financial Statements included elsewhere in this Form 10-Q.

We engage in the exploration, development and production of oil and natural gas offshore in the Gulf of Mexico and in the Gulf Coast region, with a focus on the potentially significant hydrocarbons that we believe are contained in large, deep geologic structures located beneath the shallow waters of the Gulf of Mexico shelf and onshore in the Gulf Coast region and often lying below shallow reservoirs where significant reserves have been produced. We are also pursuing plans for the potential development of the Main Pass Energy Hub^TM (MPEH^TM) project at our former sulphur mining facilities at Main Pass Block 299 (Main Pass) in the Gulf of Mexico. This project includes the conversion of our former Main Pass sulphur facilities into a hub for the receipt and processing of liquefied natural gas (LNG) and the storage and distribution of natural gas. We were previously engaged in the sulphur business until June 2002.

The North American natural gas market and world oil market both continue to reflect conditions of high demand and tight supplies. Hurricane Katrina in late August 2005 and Hurricane Rita in late September 2005 had significant negative effects on the supply and deliverability of natural gas and oil from the Gulf of Mexico. Our average realized prices during the third quarter of 2005 were $10.31 per thousand cubic feet (Mcf) for natural gas and $61.18 per barrel for oil, excluding oil production from Main Pass which averaged $55.64 per barrel for its sour crude oil. For the nine months ended September 30, 2005, our average realization was $8.26 per Mcf for natural gas and $56.16 per barrel for oil, excluding oil production from Main Pass, which averaged $52.90 (see “Results of Operations” below).

OIL & GAS ACTIVITIES

Multi-Year Exploration Venture

During 2004, we and a private partner established a multi-year exploration venture with an initial combined commitment to spend $500 million to acquire and exploit high-potential, high-risk prospects, primarily Deep Miocene structures in the shallow waters of the shelf of the Gulf of Mexico and Gulf Coast areas. We and our exploration partner have participated in seven discoveries on the 15 prospects that have been drilled and evaluated. Positive results from the Blueberry Hill well on Louisiana State Lease 340 would bring our success rate to eight of 16 prospects. Production has commenced on three of the discoveries and development plans are under way for the others.

The table below summarizes our in-progress and currently planned near-term drilling activities.

	Working Interest	Net Revenue Interest	Prospect Acreage^a	Water Depth	Proposed Total Depth^b	Current Depth ^c	Spud Date ^d
In Progress Wells:
South Marsh Island Block 224 “JB Mountain Deep”^e,f	27.5%	19.4%	2,200	10'	23,000'	20,500’	July 14, 2005
Louisiana State Lease 18090 “Long Point”^f,g	37.5%	26.8%	5,000	8’	19,000’	19,000’	July 21, 2005
Louisiana State Lease 18055 “Cane Ridge”^f	37.5%	27.5%	1,000	N/A^h	16,500’	10,000’	July 29, 2005
South Marsh Island Block 230 “Elizabeth”^e	15.0%	11.3%	10,000	18’	20,000’	11,400	September 16, 2005
West Cameron Block 95 “Cabin Creek”^e,f	37.5%	31.0%	5,000	40’	19,000’	4,500	October 15, 2005

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	Working Interest	Net Revenue Interest	Prospect Acreage^a	Water Depth	Proposed Total Depth^b	Current Depth ^c	Spud Date ^d
Development Wells:
Vermilion Blocks 16/17 “King Kong” No. 2^f,g	40.0%	29.2%	1,850	12’	13,680’	13,680’	August 12, 2005
South Marsh Island Block 225 “Hurricane” No. 2 ^f	27.5%	19.4%	7,700	10’	16,000’	9,300’	August 21, 2005
Near-Term Exploration Wells:
Louisiana State Lease 18350 “Point Chevreuil”	25.0%	17.5%	1,700	<10’	17,000’	N/A	Fourth Quarter 2005
Onshore Vermilion Parish “Liberty Canal”^f	37.5%	27.7%	1,420	N/A^h	16,000’	N/A	Fourth Quarter 2005

a.	Gross acres encompassing prospect to which we retain exploration rights.

b.	Planned target measured depth, which is subject to change.

c.	Approximate total depth of well on November 1, 2005.

d.	The timing of fourth quarter 2005 wells is subject to change.

Depending upon applicability of Deep Gas Royalty Relief eligibility criteria, the lease on which these wells are located could be eligible for royalty relief up to 25 Bcf of gas production under current Minerals Management Service (MMS) guidelines. Our net revenue interests would increase during the royalty relief period for eligible leases.

f.	Wells in which we are the operator or expect to be the operator.

g.	Well is currently being completed.

h.	Prospect located onshore Louisiana.

Exploration Activities

The JB Mountain Deep well is located on OCS 310 southeast of and adjacent to the JB Mountain discovery at South Marsh Island Block 223. We acquired additional rights in the JB Mountain Deep prospect area in 2005 and now control 5,200 gross acres in the area. This acreage is not included in the JB Mountain/Mound Point program (see “JB Mountain and Mound Point Area Development Activities” below). Our investment in JB Mountain Deep totaled $8.9 million at September 30, 2005.

The Long Point exploratory well, located onshore in Vermilion Parish, Louisiana, has been drilled to 19,000 feet and has been evaluated with log-while-drilling tools and wireline logs, indicating an interval approximating 150 gross feet of hydrocarbon bearing sands, which could potentially be a significant discovery. The wireline log indicated excellent porosity. The information gained from this well will be used to determine future drilling plans in the area. We plan to set a production liner and complete the well. Infrastructure near this onshore location in inland waters is expected to allow production to be established in early 2006.

We acquired rights to 5,000 gross acres comprising the Long Point prospect from El Paso Production Company, a subsidiary of El Paso Corporation, in June 2005 as part of a package of six deep-gas exploratory prospects covering approximately 18,000 gross acres onshore and in state waters in Vermilion Parish, Louisiana. Under the terms of the agreement, we and our private partner agreed to fund 100 percent of the drilling costs to casing point in up to six wells, representing the initial well at each prospect. At casing point of each well, El Paso can elect to participate for a 25 percent interest, and we and our private partner would own a 75 percent working interest (37.5 percent each) and an approximate 54 percent net revenue interest (approximately 27 percent each).

The Cane Ridge well, which is located onshore in Vermilion Parish, Louisiana, has a planned total depth of 16,500 feet. McMoRan operates the Cane Ridge prospect and, if successful, would earn a 37.5 percent working interest and a 27.5 percent net revenue interest. Our investment in Cane Ridge totaled $3.9 million at September 30, 2005.

We acquired rights to the Elizabeth prospect during the third quarter of 2005. The Elizabeth prospect is located offshore Louisiana on OCS 310, two blocks south of our hurricane discovery. Our investment in the Elizabeth prospect totaled $0.9 million at September 30, 2005.

In addition to the rights on six prospects acquired in June 2005, we also acquired from El Paso rights to the Cabin Creek prospect at West Cameron Block 95 in the third quarter of 2005. We and

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our private partner will fund 100 percent of the drilling costs to casing point in the well. At casing point, El Paso can elect to participate for a 25 percent interest, and we and our private partner would own a 75 percent working interest (37.5 percent each) and an approximate 62 percent net revenue interest (31 percent each).

We expect to commence drilling at least two additional prospects by year-end 2005, including Point Chevreuil and Liberty Canal, and we are also actively pursuing opportunities through our exploration venture to acquire additional acreage and prospects through farm-in or other arrangements.

Production Update and Development Activities

Our third-quarter 2005 production averaged 41 million cubic feet of natural gas equivalent per day (MMcfe/d), including approximately 1,800 barrels per day (bbls/d) of oil from Main Pass (see “Main Pass” below). Prior to Hurricane Katrina, our third-quarter 2005 production averaged approximately 55 MMcfe/d, including 2,900 bbls/d (17 MMcfe/d) from Main Pass. We are currently producing at a rate of approximately 20 MMcfe/d, which continues to increase as we reestablish production from our remaining shut-in properties, with most either commencing or anticipate to commence operations in November 2005. Our 2005 production has benefited from the resumption of production from the Main Pass field on May 6, 2005 and the commencement of production from the Hurricane Upthrown well at South Marsh Island Block 217 on March 30, 2005 and the Deep Tern C-1 sidetrack well on April 25, 2005. Production during 2005 also increased from the reversion to us of interests in properties we sold in 2002 (see “Reversionary Interests” below). Pending availability of third-party downstream facilities, we expect to average 30-40 MMcfe/d in the fourth quarter with full restoration expected in December. We expect production to increase to 60-70 MMcfe/d, including 2,900 barrels (17 MMcfe/d) from Main Pass, by the end of 2005. First-quarter 2006 production is expected to benefit from full rates at our producing fields and new production from recent discoveries, including Long Point, King Kong and West Cameron Block 43 (discussed below).

We reported positive drilling results at the King Kong No. 2 development well at Vermilion Blocks 16/17 where log-while-drilling tools indicated approximately 100 feet of possible hydrocarbon bearing sands. The King Kong No. 2 development well is a direct offset mapped updip to the King Kong No. 1 discovery well. We expect to establish production from the King Kong No. 1 well in the fourth quarter of 2005 and commence production at the No. 2 well shortly thereafter. A third well, King Kong No. 3, is being planned. As previously reported, a successful production test at King Kong No. 1 was conducted during August 2005 and indicated a gross flow rate of approximately 20.6 million cubic feet of natural gas per day (MMcf/d), approximately 3,600 bbls/d and zero barrels of water (total of approximately 42 MMcfe/d, 12 MMcfe/d net to us) on a 28/64^th choke from 34 net feet of perforations below 15,400 feet in the well.

The Hurricane No. 2 development well is located northwest of the Hurricane discovery well, which prior to Hurricane Rita was producing at a reduced rate of approximately 23 MMcf/d and 900 bbls/d (28 MMcfe/d gross, 5 MMcfe/d net to us). After production is restored, expected in the fourth quarter of 2005, the operator expects to produce the Hurricane well at a reduced rate until certain mechanical issues are resolved. Production from Hurricane is processed through the Tiger Shoal facilities, which are also being used to produce the JB Mountain and Mound Point discoveries in the OCS 310/State Lease 340 area.

We conducted a successful production test at the West Cameron Block 43 No. 4 delineation well. The well indicated a gross rate of 3.5 MMcf/d and 800 bbls/day (8.3 MMcfe/d gross, 2.7 MMcfe/d net to us) on a 14/64^th choke with flowing tubing pressure of approximately 4,100 pounds per square inch and was shut-in prior to further flow evaluation. Production from the West Cameron Block 43 field (No. 3 and No. 4 wells) is expected to commence in the first quarter of 2006. We hold a 23.4 percent working interest and an 18.0 percent net revenue interest in the West Cameron Block 43 No. 3 well and a 41.7 percent working interest and a 32.3 percent net revenue interest in the West Cameron Block 43 No. 4 well.

The development plan for the Dawson Deep discovery at Garden Banks Block 625 is being finalized by the operator. Following completion activities, the well is expected to be brought on production by mid-2006. As previously reported, the well encountered hydrocarbon-bearing sands as indicated by more than 100 feet of total vertical thickness of resistivity in the shallow zones. An additional 100 feet of hydrocarbons were logged in the deepest zone. The well was drilled to a total depth of 22,790 feet. We own a 30.0 percent working interest and a 24.0 percent net revenue interest in the Dawson Deep prospect. The Dawson Deep prospect is located on a 5,760 acre block located approximately 150 miles offshore Texas and is adjacent to the operator’s Gunnison spar facility.

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The Blueberry Hill well at Louisiana State Lease 340 reached a total depth of 23,903 feet in the first quarter of 2005. Wireline logs indicated that the well encountered four potentially productive hydrocarbon bearing sands. A 4½ inch production liner was installed and cemented to protect the identified potential pay zones. The drilling rig moved off location while the necessary 20,000-pound per square inch completion equipment for the anticipated high pressure well is procured. Completion and testing of the well will determine future plans for this prospect. The equipment for the completion has been ordered and expected delivery is early 2006. We operate Blueberry Hill, located seven miles east of the JB Mountain discovery and seven miles south southeast of the Mound Point Offset discovery. We hold a 35.3 percent working interest and a 24.2 percent net revenue interest in the Blueberry Hill well. Our investment in Blueberry Hill totaled $10.6 million at September 30, 2005.

The operator at Ship Shoal Block 296 (Raptor) has proposed two additional development wells with drilling expected to commence in late 2005. We have committed to participate in these wells. Depending upon the drilling results, a third well may also be drilled.

Main Pass

In December 2004, we acquired the remaining ownership interest in K-Mc Ventures I LLC (K-Mc I) that we did not previously own. K-Mc I owns the oil facilities and related proved oil reserves at Main Pass. The storm center of Hurricane Ivan passed within 20 miles east of Main Pass in September 2004. The Main Pass structures did not incur significant damage from Ivan but oil production from Main Pass was shut-in because of extensive damage to a third-party offshore terminal and connecting pipelines that provided throughput service for the sale of Main Pass’s sour crude oil. Insurance proceeds under our business interruption and property policies have partially mitigated the financial impact of the storm (see below). In May 2005 production resumed at Main Pass following successful modification of existing facilities at one structure formerly used in our discontinued sulphur mining business to accommodate transportation of oil production by barge. At September 30, 2005, our property, plant and equipment reflected $7.5 million of costs associated with the modification of these storage facilities. We are currently seeking reimbursement of these and subsequent modification costs under our insurance policy. Through September 30, 2005, we had received a total of $11.9 million of insurance proceeds, including $3.1 million that was treated as a reduction of our acquisition cost of K-Mc I.

On August 29, 2005, the eye wall of Hurricane Katrina passed within 50 miles west of Main Pass. While Mass Pass facilities and platforms did not suffer significant damage from Katrina, oil operations have been temporarily shut-in to perform required repairs caused by the storm. A subsurface inspection of all Main Pass structures, including those comprising the MPEH^TM, is expected to be completed in the fourth quarter of 2005. Main Pass is expected to resume oil production in the fourth quarter of 2005. We will pursue partial reimbursement of the estimated $2.5 million of costs to repair the Main Pass facilities under our property insurance policy. No business interruption claims related to Hurricanes Katrina or Rita are anticipated for Main Pass.

The crude oil produced at Main Pass contains significant amounts of sulphur and is classified as sour crude requiring the sulphur to be removed during the refining process. There is a limited market for sour crude oil and sour crude sells at a discount to other crude oils Our current contract to sell Main Pass sour crude oil terminated on November 1, 2005 and we are in discussions with a number of refineries regarding the sale of Main Pass sour crude oil from Main Pass. We anticipate that we will have a new marketing contract in place prior to year-end 2005.

The Main Pass oil lease was subject to a 25 percent overriding royalty retained by the original third party owner of the Main Pass oil lease after 36 million barrels of oil were produced, but capped at a 50 percent net profits interest. In February 2005, the original owner agreed to eliminate this royalty interest and we agreed to assume its reclamation obligation associated with one platform and the related facilities located at Main Pass which required us to record an increase of $3.9 million to property, plant and equipment as well as accrued oil and gas reclamation costs (Note 3). As a result of the transaction, the original owner will be entitled to a 6.25 percent overriding royalty in new wells, if any, drilled on the lease.

Reversionary Interests

In February 2002, we sold three oil and gas properties for $60.0 million and retained a potential reversionary interest equal to 75 percent of the transferred interests following payout of $60 million plus a specified annual rate of return. The three properties sold were Vermilion Block 196 (Lombardi), Main Pass Block 86 (Shiner), and 80 percent of our interest in Ship Shoal Block 296 (Raptor). During the

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first quarter of 2005, we reached agreement with the third-party purchaser to assign to us the 75 percent reversionary interest in Raptor effective February 1, 2005 increasing our working interest to approximately 49.4 percent and our net revenue interest to 34.8 percent. Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout. Accordingly, we have an approximate 35.6 percent working interest and a 25.7 percent net revenue interest in the Lombardi field and a 53.4 percent working interest and a 38.5 percent net revenue interest in the Shiner field. We were designated operator of the Shiner field effective July 1, 2005. In connection with the reversion of the interests in these properties and in accordance with current accounting rules, we recorded $2.1 million to property, plant and equipment as well as accrued oil and gas reclamation obligations related to assuming our interest in these properties’ reclamation liabilities (Note 3). The five wells at these three properties produced at an average rate of approximately 12 MMcfe/d, net to our interest in the third quarter. The Shiner field has been shut-in since Hurricane Katrina and the Lombardi field has been shut-in since Hurricane Rita. Raptor, also shut-in from Hurricane Rita, restored its production in October 2005. The Shiner and Lombardi fields are expected to resume production in the fourth quarter of 2005.

JB Mountain and Mound Point Area Development Activities

We are a participant in a program that began in 2002 and includes the JB Mountain and Mound Point Offset discoveries in the OCS 310 and Louisiana State Lease 340 areas, respectively. The program currently holds a 55 percent working interest and a 38.8 percent net revenue interest in the JB Mountain prospect and a 30.4 percent working interest and a 21.6 percent net revenue interest in the Mound Point Offset prospect. Under the terms of the program, the third party partner is funding all costs attributable to the program’s interests in the properties, and will own all of the program’s interests until the program’s aggregate production totals 100 Bcfe attributable to the program’s net revenue interest, at which point 50 percent of the program’s interests would revert to us.

There are currently three producing wells and approximately 13,000 gross acres on Louisiana State Lease 340 and OCS 310 that are subject to the 100 Bcfe arrangement. We believe there are further exploration and development opportunities associated with this acreage. Future exploration and development activities on the acreage involved in the program is dependent on decisions by the third party partner, as operator, and other co-owners in the properties. The three producing wells in the program averaged an aggregate gross rate of approximately 40 MMcfe/d during the third quarter of 2005. These wells were not damaged by the Hurricane Rita, but have been shut-in since the storm because of damage to third-party downstream processing facilities. Production is expected to be restored on these wells during the fourth quarter of 2005.

In 2004, we reacquired rights involving approximately 45,000 gross acres in the Louisiana State Lease 340/Mound Point and OCS 310/JB Mountain areas, which were previously part of this program. This reacquired acreage includes the Hurricane Upthrown and JB Mountain Deep prospects at OCS 310, the Blueberry Hill prospect, two Mound Point wells that were previously temporarily abandoned and the Mound Point - West Fault Block prospect at Louisiana State Lease 340. We are considering further operations with respect to the temporarily abandoned Mound Point wells, which may include sidetracking, deepening or re-drilling these two wells.

MAIN PASS ENERGY HUB^TM PROJECT

We are pursuing plans for the potential development of the MPEH^TM Project. Through September 30, 2005, we have incurred approximately $24.0 million of cash costs associated with this project, including $2.7 million during the third quarter of 2005 and $7.6 million for the nine months ended September 30, 2005. We expect to spend approximately $3 million to advance the licensing process and to pursue commercial arrangements for the project during the fourth quarter of 2005.

The MPEH^TM is located in 210 feet of water, which allows deepwater access for large LNG tankers and is in close proximity to shipping channels. We plan to use the substantial existing platforms and infrastructure at the site, which we believe will provide us potential significant timing advantages and cost savings. Safety and security aspects of the facility would also be enhanced by the offshore location. Subject to the timing of issuance of our license and obtaining financing for the project, we believe the facilities could be operational in 2009, which would make MPEH^TM one of the first U.S. offshore LNG terminals.

Currently, we own 100 percent of the MPEH^TM project. However, two entities have separate options to participate as passive equity investors for up to an aggregate 25 percent of our equity interest in

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the project (see Notes 4 and 11 of our 2004 Form 10-K). Future joint venture and financing arrangements may also reduce our equity interest in the project.

The proposed terminal would be capable of regasifying LNG at a rate of 1 Bcf per day and is being designed to accommodate potential future expansions. The capital cost for the terminal facilities is currently estimated at $440 million. We are seeking a permit for a facility with capacity up to 1.6 Bcf per day; developing the incremental capacity would add approximately $100 million to the estimated capital cost.

We are also considering additional investments to develop undersea cavern storage for natural gas in the 2-mile diameter salt dome located at the site and to construct pipeline interconnects to the U.S. pipeline distribution system, including a new 93-mile, 36-inch pipeline to Coden, Alabama. Current plans for the MPEH^TM include 28 Bcf of initial cavern storage capacity and aggregate peak deliverability from the proposed terminal, including deliveries from storage of up to 2.5 Bcf per day. The estimated cost for these potential investments in pipelines and storage is approximately $450 million.

As discussed in “Oil & Gas Activities - Main Pass” above, Hurricane Katrina’s eye wall passed approximately 50 miles west of Main Pass. The initial assessment was that the storm had no apparent significant structural impact to the MPEH^TM platforms. A subsurface inspection will be completed. The MPEH^TM platforms were not significantly affected by Hurricane Rita. The MPEH^TMplatforms were designed to withstand significant hurricane events.

Pursuant to the requirements of the U.S. Deepwater Port Act, we filed an application with the U.S. Coast Guard (Coast Guard) and the Maritime Administration (MARAD) in February 2004 requesting a license to develop the MPEH^TM project. Subsequent to filing the license application, the statutory review period was temporarily suspended while we provided the Coast Guard with additional information relating to the potential impact of the project on the marine habitat, air emissions, cavern design and other matters. On April 21, 2005, the Coast Guard resumed the statutory review period of our license application with an eight month timeline remaining under the 330-day review process.

The most significant issue that has arisen in the licensing process for the MPEH^TM and other offshore LNG projects is the use of open rack vaporizers, sometimes referred to as an “open-loop” system, that utilize seawater to heat LNG to convert it to natural gas. Concerns have been expressed in the licensing process about the potential impact of this process on marine life. Commercial and recreational fishing interests, as well as environmental groups, have taken positions opposing open-loop systems. Two offshore LNG projects using open-loop systems have been granted licenses but, in the second quarter of 2005, the Governors of Louisiana, Mississippi and Alabama, states adjacent to our proposed MPEH^TMproject, publicly announced opposition to the use of open-loop systems until additional data are made available that would demonstrate that the operation of the open rack vaporizer will not have an unacceptable impact on marine life. A provision in the Deepwater Port Act allows the governor of an adjacent state to veto a license application.

In June 2005, the Coast Guard and MARAD published a draft Environmental Impact Statement (EIS) for our MPEH^TM license application. The draft EIS evaluates potential environmental impacts associated with the construction and operation of the MPEH^TM. The Coast Guard and MARAD, which work in collaboration with the National Marine Fisheries Service, the Environmental Protection Agency and other government agencies, stated in the draft EIS that the proposed project would not have unacceptable adverse environmental impacts and, specifically, the proposed open-loop system would not have a significant adverse impact on marine life in the Gulf of Mexico.

The Coast Guard conducted public meetings during July 2005 to allow comments on the draft EIS. On August 26, 2005, the Coast Guard requested additional information in response to comments received on the draft EIS, primarily related to fisheries, air quality and water quality issues. The Coast Guard again temporarily suspended the 330-day review period on August 26, 2005, indicating the suspension would be of short duration, in order to accommodate the information request and scheduling adjustment. Following Hurricane Katrina, the Coast Guard advised all Deepwater Port applicants, including MPEH^TM, that it is currently unable to schedule the public hearings that are necessary to resume processing of the applications because of the State of Emergency in the Gulf of Mexico. The Coast Guard indicated that they recognize the importance of these projects and will move forward as soon as practicable.

Following publication of the final EIS, additional public meetings will be held. Under the Deepwater Port Act, a Record of Decision on a license application is required within 90 days of the final public hearing. The timing or outcome of the review and approval process depends on circumstances beyond our control.

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We are in discussions with potential LNG suppliers in the Atlantic Basin and with natural gas consumers in the United States regarding commercial arrangements for the facilities. We are advancing commercial discussions in parallel with the permitting process.

For additional information regarding our MPEH^TM Project see Items 1. and 2. “Business and Properties - Main Pass Energy Hub^TM Project” in our 2004 Form 10-K.

RESULTS OF OPERATIONS

Our only segment is “Oil and Gas,” which includes all oil and gas exploration and production operations of MOXY and K-Mc I. We are pursuing a new business segment, “Energy Services,” whose start-up activities are reflected as a single expense line item within the accompanying consolidated statements of operations. See “Discontinued Operations” below for information regarding our former sulphur segment. The activities of K-Mc I’s oil operations at Main Pass, which were shut-in from September 2004 to early May 2005 and subsequent to August 29, 2005 (see “ Oil and Gas Activities - Main Pass” above), are included in our consolidated results for 2005. Prior to December 27, 2004, we accounted for our investment in K-Mc I using the equity method of accounting.

We use the successful efforts accounting method for our oil and gas operations, under which our exploration costs, other than costs of successful drilling and in-progress exploratory wells, are charged to expense as incurred. We may experience operating losses during the near-term, primarily because of the scope of our expected exploration activities and the start-up costs associated with establishing the MPEH^TM,including permitting fees and the costs to pursue commercial arrangements.

During the third quarter of 2005, we had operating income of $11.3 million. Our operating results primarily reflect increased production from our recent discoveries, production from Main Pass and the reversion to us of interests in the three properties we sold in February 2002. Our third quarter 2005 results included $5.8 million of exploration expenses, including nonproductive exploratory well drilling and related costs of $2.7 million, and $2.7 million of start-up costs associated with the MPEH^TM. During the third quarter of 2004, we had an operating loss of $5.6 million, attributable to $2.7 million of start-up costs associated with the MPEH^TM and $3.2 million of exploration expense.

For the nine months ended September 30, 2005 our operating loss totaled $3.1 million compared with $22.3 million for the same period last year. Our operating loss for the nine-month 2005 period included $41.9 million of exploration expenses, including $31.6 million of nonproductive well drilling and related costs, and $7.6 million of start-up costs associated with MPEH^TM. Our operating loss during the nine-month 2005 period was partially offset by increased production and an $8.9 million insurance recovery associated with our Main Pass oil operations. Our operating loss for the nine-month 2004 period included $16.7 million of exploration expense, including $9.5 million of nonproductive exploratory drilling and related costs. Our start-up costs associated with the MPEH^TM totaled $8.7 million for the nine months ended September 30, 2004. Summarized operating data is as follows:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
Sales volumes:
Gas (thousand cubic feet, or Mcf)	2,011,900	499,600	6,187,100	1,247,600
Oil, excluding Main Pass 299 (barrels)	89,400	13,700	186,200	51,200
Oil from Main Pass 299 (barrels) ^a	235,000	-	335,600	-
Plant products (equivalent barrels) ^b	42,500	5,400	78,000	17,200
Average realizations:
Gas (per Mcf)	$ 10.31	$ 5.65	$ 8.26	$ 5.98
Oil, excluding Main Pass 299 (per barrel)	61.18	43.25	56.16	37.96
Oil from Main Pass 299 (per barrel)	55.64	-	52.90	-

Main Pass 299 resumed production on May 6, 2005 following successful modification of existing storage tanks to accommodate transportation of oil from the field by barge. In late August 2005, Main Pass was shut-in following Hurricane Katrina; however production is expected to resume in fourth quarter of 2005. At September 30, 2005, we had approximately 30,000 barrels of oil inventory attributable to the Main Pass operations.

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We received approximately $1.9 million and $3.3 million of revenues associated with plant products (ethane, propane, butane, etc.) during the third quarter of 2005 and nine months ending September 30, 2005, respectively, compared with $0.2 million and $0.5 million of plant product revenues in the comparable periods last year. The increase in plant product revenue in 2005 reflects commencement of production from our recent discoveries, specifically production from the Hurricane and Deep Tern fields.

Oil and Gas Operations

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

	Third Quarter			Nine Months
Oil and gas revenues - prior year period	$	3,704	$	10,218
Increase in:
Price realizations:
Gas		9,375		14,107
Oil, excluding Main Pass 299		1,603		3,389
Sales volumes:
Gas		8,544		29,538
Oil, excluding Main Pass 299		3,274		5,125
Revenue from oil production at Main Pass 299		13,077		17,757
Plant products revenues		1,699		2,817
Other		135		715
Oil and gas revenues - current year period	$	41,411	$	83,666

Our third-quarter 2005 oil and gas revenues increased substantially over the same period last year reflecting significant increases in volumes sold of both natural gas and oil. The increase in sales volumes reflects the resumption of oil production from Main Pass in May 2005 and the establishment of production at our recent discoveries including from the Hurricane Upthrown well on March 30, 2005, the Deep Tern C-1 sidetrack on April 29, 2005, the Deep Tern C-2 well on December 30, 2004 and the Minuteman well on February 25, 2005 (for more information regarding the Minuteman well see Note 3 “Multi-Year Exploration Venture”). Our third-quarter 2005 sales volumes also reflect the reversion to us of interests (see “Oil and Gas Activities - Reversionary Interests” above) in properties we sold in February 2002. Our third quarter 2005 production also reflects the increase in our net revenue interest in the West Cameron Block 616 field from 5 percent to approximately 19.3 percent following payout of the field in September 2004. Average realizations received during the third quarter of 2005 increased for both natural gas (82 percent) and oil (41 percent), excluding Main Pass, over realizations received during the same period last year.

The increase in our oil and gas revenues during the nine months ended September 30, 2005 compared with the same period last year primarily reflects the factors discussed above for the third-quarter periods. Average realizations received during the nine months ended September 30, 2005 increased for both natural gas (38 percent) and oil (48 percent), excluding Main Pass, compared with realizations received during the nine months ended September 30, 2004.

Our service revenues totaled $2.9 million for the third quarter of 2005 and $9.2 million for the nine months ended September 30, 2005 compared to $3.6 million and $10.6 million for the comparable periods last year. Our service revenue is primarily attributable to the management fee associated with the multi-year exploration venture (Note 3) and fees for processing third party oil and gas production at our Main Pass oil facilities.

Production and delivery costs totaled $12.5 million in the third quarter of 2005 and $20.9 million for the nine months ended September 30, 2005 compared to $1.6 million and $4.7 million for the comparable periods in 2004. These increases reflect the production costs associated with the Main Pass oil operations, which totaled $8.6 million during the third quarter and $13.5 million for the nine months ended September 30, 2005, and additional costs relating to increased natural gas and oil production for the 2005 periods as compared with the comparable 2004 periods. Production costs during the third quarter of 2005 include estimated hurricane damage repair costs of $2.8 million, including $2.5 million for Main Pass

Depletion, depreciation and amortization expense totaled $6.5 million in the third quarter of 2005 and $19.4 million for the nine months ended September 30, 2005 compared with $1.7 million and $4.1 million for the same periods last year. The increases primarily reflect higher production volumes resulting from new fields with lower depreciable basis commencing production in the first half of 2005 and depreciation associated with oil production from Main Pass.

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Our exploration expenses fluctuate based on the outcome of drilling exploratory wells, the structure of our drilling arrangements and the incurrence of geological and geophysical costs, including the cost of seismic data. Summarized exploration expenses are as follows (in millions):

	Third Quarter						Nine Months
	2005			2004			2005			2004
Geological and geophysical	$	2.5		$	0.7		$	5.3		$	4.2
Nonproductive exploratory costs, including
related lease costs		2.7	^a		1.9	^b		31.6	^a,c		9.5	^b,d
Other		0.7			0.6			5.0	^e		3.0
	$	5.9		$	3.2		$	41.9		$	16.7

a.	Includes $1.4 million of nonproductive exploratory drilling and related costs associated with the “Delmonico” well at Louisiana State Lease 1706 incurred in July 2005 and $1.1 million of drilling costs associated with the “Little Bay” well at Louisiana State Lease 5097.

b.	Includes nonproductive exploratory drilling and related costs for the Poblano well at East Cameron Block 137 incurred as of September 30, 2004 totaling $1.5 million.

Includes nonproductive exploratory well costs associated with the “Korn” well at South Timbalier Blocks 97/98 ($6.9 million), the “Little Bay” well ($12.1 million), the “Delmonico” well ($8.9 million), the “Caracara” well at Vermilion Blocks 227/228 ($1.3 million), the “King of the Hill” well at High Island Block 131 ($0.3 million), the “Gandalf ” well at Mustang Island Block 829 ($0.2 million) and the deeper zones at both the “Hurricane Upthrown” well at South Marsh Island Block 217 ($0.4 million) and the West Cameron Block 43 No. 3 exploratory well ($0.4 million). Amount also includes the write-off of approximately $1.5 million of leasehold costs.

d.	Reflects $7.2 million of nonproductive exploratory drilling and related costs for the Lombardi Deep well ($0.4 million charged to expense during the third quarter of 2004) and $0.7 million for the costs incurred on the Hurricane well at South Marsh Island Block 217 during the first quarter of 2004.

e.	Includes insurance costs associated with our increasing exploration drilling activities. Increase over 2004 periods also includes higher delay rental payments to maintain portions of our acreage position.

As discussed above, our results included an insurance recovery totaling $8.9 million for the nine months ended September 30, 2005 related to our Main Pass business interruption claim. During the second quarter of 2004, we received insurance proceeds of $1.1 million as partial reimbursement of costs previously charged to production and delivery costs following Hurricane Lili, which occurred in the third quarter of 2003.

Other Financial Results

General and administrative expense totaled $5.5 million in the third quarter of 2005 and $15.1 million for the nine months ended September 30, 2005 compared with $3.8 million in the third quarter of 2004 and $10.2 million for the nine months ended September 30, 2004. The increases include higher personnel costs associated with our expanded exploration and production activities and additional costs associated with ongoing legal proceedings described in Note 3 and Part II - Legal Proceedings elsewhere in this Form 10-Q. Additionally, during the third quarter of 2005, we incurred $0.7 million of costs associated with contributions, employee assistance and other administrative costs following Hurricane Katrina (Note 3), including $0.5 million charged to general and administrative expense and the remainder to exploration expense. General and administrative expense included noncash compensation costs associated with stock based awards totaling $0.1 million during the third quarter of 2005 and 2004, $0.5 million for the nine months ended September 30, 2005 and $0.3 million for the nine months ended September 30, 2004.

Interest expense, net of capitalized interest, totaled $4.0 million in the third quarter of 2005 and $11.9 million for the nine months ended September 30, 2005 compared with $2.1 million in the third quarter of 2004 and $6.5 million for the nine months ended September 30, 2004. Capitalized interest totaled $0.3 million in the third quarter of 2005, $0.2 million in the third quarter of 2004, $1.2 million for the nine months ended September 30, 2005 and $0.4 million for the nine months ended September 30, 2004. The increase in interest expense between the comparable 2005 and 2004 periods reflect the issuance of $140 million of 5¼% convertible senior notes in October 2004.

Other income totaled $1.5 million in the third quarter of 2005 and $4.5 million for the nine months ended September 30, 2005 compared with $0.3 million and $0.7 million for the same periods last year. The increase primarily reflects higher interest income on our cash equivalent balance, which reflects the

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completion of our two capital transactions in October 2004 that raised approximately $231 million. Our unrestricted cash balance, a substantial amount of which is invested in short-term instruments, totaled approximately $172 million at September 30, 2005.

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 the discontinued operations (in millions):

	Nine Months Ended September 30
	2005			2004
Continuing operations
Operating	$	64.7		$	(16.5	)
Investing		(91.8	)		(17.5	)
Financing		0.9			(0.8	)

Discontinued operations
Operating	(2.5	)	(4.2	)
Investing	-		(5.9	)
Financing	-		-

Total cash flow
Operating	62.2		(20.7	)
Investing	(91.8	)	(23.4	)
Financing	0.9		(0.8	)

Nine-Month 2005 Cash Flows Compared with Nine-Month 2004

Operating cash flow from our continuing operations during the nine months ended September 30. 2005 reflects increased oil and gas revenues, the advance billing and receipt of certain exploratory drilling costs from our drilling partners, a decrease in the amount of start-up costs incurred associated with the MPEH^TMand other working capital changes, including the receipt of insurance proceeds related to our Main Pass claim (see “Oil and Gas Activities-Main Pass” and Note 3).

Our investing cash flow reflects exploration, development and other capital expenditures (collectively “capital expenditures) for our in-progress exploratory wells and development wells as discussed in “Oil and Gas Activities” above as well as our costs to modify certain storage facilities at Main Pass to accommodate transportation of its oil production by barge. capital These expenditures also include nonproductive exploratory well costs as discussed in “Results of Operations” above. Our capital expenditures totaled $102.9 million for the nine months ended September 30, 2005. We anticipate our capital expenditures will approximate $175 million, including an additional $45 million for exploration expenses and $25 million for currently identified development costs, by year-end 2005. We expect this level of capital spending to continue into 2006. Our twelve-month projection of capital spending approximates $185 million, consisting of $110 million for exploration expense and $75 million for development of prospects. These planned capital expenditures are subject to change because of timing and other factors and may increase as additional exploration opportunities are presented to us or to fund the development costs associated with additional successful wells.

Our investing cash flows during the nine months ended September 30, 2005 also include the liquidation of $11.5 million of our U.S. government notes previously escrowed to pay the semi-annual interest payments on our 6% convertible senior notes due on January 2, 2005 and July 2, 2005 (total $7.8 million) and 5¼% convertible senior notes on April 6, 2005 ($3.7 million). During the nine months ended September 30, 2004, we liquidated a total of $7.8 million of our escrowed U.S. government notes to pay the semi-annual interest payments on our 6% convertible senior notes. Investing cash flow used by our discontinued sulphur operations totaled $5.9 million during the first half of 2004, which reflects the $7.0 million payment to terminate the lease on the remaining sulphur railcars, net of $1.1 million of proceeds received from their sale to a third party.

Our continuing operations’ financing activities included payment of dividends on our mandatorily redeemable preferred stock of $1.1 million for the nine months ended September 30, 2005 and 2004. Proceeds received from the exercise of stock options totaled $2.0 million during the nine months ended September 30, 2005 and $0.4 million for the same period in 2004.

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DISCONTINUED OPERATIONS

The summarized results of the discontinued operations are as follows (in thousands):

	Third Quarter						Nine Months
	2005			2004			2005		2004
Sulphur retiree costs ^a	$	299		$	469		$	701	$	1,767
Legal expenses ^b		(32	)		346			354		1,495
Caretaking costs		479			363			922		787
Accretion expense - sulphur
reclamation obligations		240			216			720		650
Insurance		345			(706	)^c		529		(454	)^c
General and administrative		66			74			143		183
Other		227	^d		(495	)^e		222		(752	)^e
Loss from discontinued operations	$	1,624		$	267		$	3,591	$	3,676

The decrease during 2005 reflect lower expected costs associated with an obligation to reimburse a third party for a portion of the postretirement benefit costs relating to certain retired sulphur employees. The decrease primarily resulted from certain plan changes made by the plan sponsor that decreased the number of former employees covered by the obligation and the amount of future benefits to be paid.

b.	The decreases during 2005 reflect the July 2004 settlement of certain litigation involving the reclamation of certain sulphur structures at Main Pass.

c.	During the third quarter of 2004, we reduced our estimated uninsured workers compensation and general liability claims following completion of an analysis of such matters, resulting in a $0.8 million decrease in our accrued liability.

Primarily reflects estimated repairs and related costs associated with our inactive Port Sulphur, Louisiana facilities following Hurricane Katrina. We are assessing various alternatives for the ultimate closure of these facilities, which may result in changes in the related timing and/or estimated costs.

e.	Includes $0.3 million gain on the sale of materials and supply inventory previously charged to expense in June 2000 and a $0.3 million gain on the settlement of an environmental liability partially offset by certain costs incurred to evaluate and remediate other environmental liabilities.

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 potential oil and gas discoveries on drilling prospects; exploration activities; development and production activities; anticipated and potential production and flow rates; potential reversionary interests; the economic potential of properties; estimated exploration costs; general economic and business conditions; the potential Main Pass Energy Hub^TM Project, the expected near-term funding of the related permitting process, the estimated capital costs for developing the project and the outcome of future litigation. Accuracy of the projections depends on assumptions about events that change over time and is thus susceptible to periodic change based on actual experience and new developments. We caution readers that we assume no obligation to update or publicly release any revisions to the forward looking information in this Form 10-Q and, except to the extent required by applicable law, do not intend to update or otherwise revise such information more frequently than quarterly. Important factors that might cause future results to differ from our expectations include: variations in the market prices of oil and natural gas; drilling results; unanticipated fluctuations in flow rates of producing wells; actual oil and gas production, which may differ from reserve estimates; the ability to satisfy future cash obligations and environmental costs; general exploration and development risks and hazards; availability of third party downstream facilities; the feasibility of the potential Main Pass Energy Hub^TMand the ability to obtain significant project financing and regulatory approvals for such project. 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 “Risk Factors” included in Items 1. and 2. “Business and Properties” in our 2004 Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk.

There have been no significant changes in our market risks since the year ended December 31, 2004. For more information, please read the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2004.

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-14(c) and 15d-14(c) 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 in timely alerting them to material information relating to McMoRan (including our consolidated subsidiaries) required to be disclosed in our periodic Commission filings.

(b) Changes in internal controls. There has been no change in our internal control over financial reporting that occurred during the third fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II--OTHER INFORMATION

Item 1. Legal Proceedings.

Daniel W. Krasner v. James R. Moffett; René L. Latiolais; J. Terrell Brown; Thomas D. Clark, Jr.; B.M. Rankin, Jr.; Richard C. Adkerson; Robert M. Wohleber; Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co., Civ. Act. No. 16729-NC (Del. Ch. filed Oct. 22, 1998). Gregory J. Sheffield and Moise Katz v. Richard C. Adkerson, J. Terrell Brown, Thomas D. Clark, Jr., René L. Latiolais, James R. Moffett, B.M. Rankin, Jr., Robert M. Wohleber and McMoRan Exploration Co., (Court of Chancery of the State of Delaware, filed December 15, 1998.) These two lawsuits were consolidated in January 1999. The complaint alleges that the directors of Freeport-McMoRan Sulphur Inc. breached their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the merger of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. The plaintiffs claim that the directors failed to take actions that were necessary to obtain the true value of Freeport-McMoRan Sulphur Inc. The plaintiffs also claim that McMoRan Oil & Gas Co. knowingly aided and abetted the breaches of fiduciary duty allegedly committed by the other defendants. In September 2002, the Chancery Court granted the defendants’ motion to dismiss. The plaintiffs appealed the decision, and in June 2003 the Delaware Supreme Court reversed the trial court’s dismissal and remanded the case to the trial court for further proceedings. The lawsuit was certified as a class action in January 2005. In February 2005 the defendants filed a motion for summary judgment, and on June 30, 2005, the Chancery Court rendered a written opinion denying defendants’ motion for summary judgment. A trial on the merits was scheduled for September 2005 but following Hurricane Katrina in late August 2005, the trial has been rescheduled to May 2006.

We believe that the 1998 merger transaction was properly considered by the boards of directors of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. and that the transaction was substantively and procedurally fair to the shareholders of both companies. Although the plaintiffs seek damages in a material amount, we cannot predict the outcome of this dispute or estimate the amount of any loss that may result to our company from it. Accordingly, no amounts have been accrued in our financial statements for this contingency.

Other than the proceeding discussed above, 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 coverages customary in our business, with coverage limits as we deem prudent.

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/ C. Donald Whitmire, Jr.

C. Donald Whitmire, Jr.

Vice President and Controller-

Financial Reporting

(authorized signatory and

Principal Accounting Officer)

Date: November 3, 2005

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McMoRan Exploration Co.

Exhibit Index

Exhibit Number

2.1	Agreement and Plan of Mergers dated as of August 1, 1998. (Incorporated by reference to Annex A to McMoRan’s Registration Statement on Form S-4 (Registration No. 333-61171) filed with the SEC on October 6, 1998 (the McMoRan S-4)).

3.1	Amended and Restated Certificate of Incorporation of McMoRan. (Incorporated by reference to Exhibit 3.1 to McMoRan’s 1998 Annual Report on Form 10-K (the McMoRan 1998 Form 10-K)).

3.2	Certificate of Amendment to the Amended and Restated Certificate of Incorporation of McMoRan. (Incorporated by reference to Exhibit 3.2 of McMoRan’s First-Quarter 2003 Form 10-Q).

3.3	Amended and Restated By-laws of McMoRan as amended effective February 2, 2004. (Incorporated by reference to Exhibit 3.3 to McMoRan’s 2003 Annual Report on Form 10-K (the McMoRan 2003 Form 10-K)).

4.1	Form of Certificate of McMoRan Common Stock (Incorporated by reference to Exhibit 4.1 of the McMoRan S-4).

4.2	Rights Agreement dated as of November 13, 1998. (Incorporated by reference to Exhibit 4.2 to McMoRan 1998 Form 10-K).

4.3	Amendment to Rights Agreement dated December 28, 1998. (Incorporated by reference to Exhibit 4.3 to McMoRan 1998 Form 10-K).

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. (Incorporated by reference to Exhibit 4.4 to McMoRan’s Third Quarter 1999 Form 10-Q).

4.5	Form of Certificate of McMoRan 5% Convertible Preferred Stock (McMoRan Preferred Stock). (Incorporated by reference to Exhibit 4.5 to McMoRan’s Second Quarter 2002 Form 10-Q).

4.6	Certificate of Designations of McMoRan Preferred Stock. (Incorporated by reference to Exhibit 4.6 to McMoRan’s Third-Quarter 2002 Form 10-Q).

4.7	Warrant to Purchase Shares of Common Stock of McMoRan Exploration Co. dated December 16, 2002. (Incorporated by reference to Exhibit 4.7 to McMoRan’s 2002 Form 10-K).

4.8	Warrant to Purchase Shares of Common Stock of McMoRan Exploration Co. dated September 30, 2003. (Incorporated by reference to Exhibit 4.8 to McMoRan’s 2003 Form 10-K),

4.9	Registration Rights Agreement dated December 16, 2002 between McMoRan Exploration Co. and K1 USA Energy Production Corporation. (Incorporated by reference to Exhibit 4.8 to McMoRan’s 2002 Form 10-K).

4.10	Indenture dated as of July 2, 2003 by and between McMoRan and The Bank of New York, as trustee. (Incorporated by reference to Exhibit 4.9 to McMoRan’s Second-Quarter 2003 Form 10-Q).

E-1

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4.11	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. (Incorporated by reference to Exhibit 4.11 to McMoRan’s Second-Quarter 2003 Form 10-Q).

4.12	Indenture dated October 6, 2004 by and among McMoRan and the Bank of New York, as trustee. (Incorporated by reference to Exhibit 99.3 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004).

4.13	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. (Incorporated by reference to Exhibit 99.4 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004).

4.14	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. (Incorporated by reference to Exhibit 99.5 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004).

10.1	Main Pass 299 Sulphur and Salt Lease, effective May 1, 1988. (Incorporated by reference to Exhibit 10.1 to McMoRan’s 2001 Annual Report on Form 10-K (the McMoRan 2001 Form 10-K)).

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. (Incorporated by reference to Exhibit 10.10 to McMoRan’s Second Quarter 2002 Form 10-Q).

10.3	Amended and Restated Services Agreement dated as of January 1, 2002 between McMoRan and FM Services Company. (Incorporated by reference to Exhibit 10.3 to McMoRan’s Second-Quarter 2003 Form 10-Q).

10.4	Letter Agreement dated August 22, 2000 between Devon Energy Corporation and Freeport Sulphur. (Incorporated by reference to Exhibit 10.36 to McMoRan’s Third-Quarter 2000 Form 10-Q).

10.5	Asset Purchase Agreement dated effective December 1, 1999 between SOI Finance Inc., Shell Offshore Inc. and MOXY. (Incorporated by reference to Exhibit 10.33 in the McMoRan 1999 Form 10-K).

10.6	Employee Benefits Agreement by and between Freeport-McMoRan Inc. and Freeport Sulphur (Incorporated by reference to Exhibit 10.29 to McMoRan’s 2001 Form 10-K).

10.7	Purchase and Sales agreement dated January 25, 2002 but effective January 1, 2002 by and between MOXY and Halliburton Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated February 22, 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. (Incorporated by reference to Exhibit 10.37 to McMoRan’s First-Quarter 2002 Form 10-Q.)

10.9	Purchase and Sale Agreement dated May 9, 2002 by and between MOXY and El Paso Production Company. (Incorporated by reference to Exhibit 10.28 to McMoRan’s Second Quarter 2002 Form 10-Q).

10.10	Amendment to Purchase and Sale Agreement dated May 22, 2002 by and between MOXY and El Paso Production Company. (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second Quarter 2002 Form 10-Q).

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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 Exploration Co. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 2002 Form 10-K).

	Executive and Director Compensation Plans and Arrangements (Exhibits 10.12 through 10.32).

10.12	McMoRan Adjusted Stock Award Plan, as amended. (Incorporated by reference to Exhibit 10.15 to McMoRan’s 2003 Form 10-K)

10.13	McMoRan 1998 Stock Option Plan. (Incorporated by reference to Exhibit 10.13 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.14	McMoRan 1998 Stock Option Plan for Non-Employee Directors. (Incorporated by reference to Exhibit 10.14 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.15	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 1998 Stock Option Plan. (Incorporated by reference to Exhibit 10.15 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.16	McMoRan 2000 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.16 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.17	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2000 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.17 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.18	McMoRan 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.18 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.19	McMoRan 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.19 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.20	McMoRan’s Performance Incentive Awards Program as amended effective February 1, 1999. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 1998 Form 10-K).

10.21	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.21 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.22	McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.22 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.23	McMoRan Financial Counseling and Tax Return Preparation and Certification Program, effective September 30, 1998. (Incorporated by reference to Exhibit 10.26 to McMoRan’s First-Quarter 2003 Form 10-Q)

10.24	McMoRan Form of Notice of Grants of Nonqualified Stock Options and Limited Rights under the 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.24 to McMoRan’s Second-Quarter 2005 Form 10-Q).

10.25	McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.25 to McMoRan’s Second-Quarter 2005 Form 10-Q).

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10.26	McMoRan 2004 Director Compensation Plan. (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.27	Agreement for Consulting Services between Freeport-McMoRan and B. M. Rankin, Jr. effective as of January 1, 1991)(assigned to FM Services as of January 1, 1996); as amended on December 15, 1997 and on December 7, 1998. (Incorporated by reference to Exhibit 10.32 to McMoRan 1998 Form 10-K).

10.28	Supplemental Agreement between FM Services and B.M. Rankin, Jr. effective as of January 1, 2005. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated January 19, 2005 (filed January 24, 2005).

10.29	McMoRan Director Compensation. (Incorporated by reference to Exhibit 10.27 to McMoRan’s 2004 Form 10-K).

10.30	McMoRan Exploration Co. 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K filed on May 6, 2005).

10.31	Form of Notice of Grant of Nonqualified Stock Options under the 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.2 to McMoRan’s Current Report on Form 8-K filed May 6, 2005).

10.32	Form of Restricted Stock Unit Agreement under the 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.3 to McMoRan’s Current Report on Form 8-K filed May 6, 2005).

15.1	Letter dated November 2, 2005 from Ernst & Young LLP regarding unaudited interim financial statements.

31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a)/15d-14(a).

31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a).

32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350.

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McMoran Exploration (MMR) Inactive 10-Q2005 Q3 Quarterly report

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